UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM 10-K
(Mark
One)
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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, 2007
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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(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(d) 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. ý
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer ý Accelerated filer □
Non-accelerated
filer □
Smaller reporting company
□
(Do not check if a smaller reporting
company)
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
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, 2007, was $2,040,161,249.
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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76,357,138
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January
31, 2008
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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 2008 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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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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Table of Contents
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Item
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Page
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Number
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Number
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Part
I
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Part
II
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Part
III
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95
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Part
IV
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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 or Vectren North),
Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the
Ohio operations (VEDO or Vectren Ohio). 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
are holding companies as defined by the Energy Policy Act of 2005 (Energy
Act). Vectren was incorporated under the laws of Indiana on June 10,
1999.
Indiana
Gas provides energy delivery services to over 568,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 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 percent ownership), and Indiana Gas (47
percent ownership). The Ohio operations generally do business as
Vectren Energy Delivery of Ohio.
The
Company, through Vectren Enterprises, Inc. (Enterprises), is 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 services and performance contracting and renewable
energy 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 in the past
invested in projects that generated 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: the Utility Group, the
Nonutility Group, and Corporate and Other. At December 31, 2007, the
Company had $4.3 billion in total assets, with $3.6 billion (84 percent)
attributed to the Utility Group, $0.7 billion (16 percent) attributed to the
Nonutility Group, and less than $0.1 billion attributed to Corporate and
Other. Net income for the year ended December 31, 2007, was $143.1
million, or $1.89 per share of common stock, with net income of $106.5 million
attributed to the Utility Group and $37.0 million attributed to the Nonutility
Group, and a net loss of $0.4 million 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. 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 the Gas Utility Services operating segment and the
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, 2007, the Company supplied natural gas service to approximately
998,000 Indiana and Ohio customers, including 911,000 residential, 85,000
commercial, and 2,000 industrial and other contract customers. This
represents customer base growth of 0.3 percent compared to
2006.
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, Bloomington, Terre Haute, and
suburban areas surrounding Indianapolis and Indiana counties near Louisville,
Kentucky. The largest community served outside of Indiana is Dayton,
Ohio.
Revenues
For the
year ended December 31, 2007, gas utility revenues were approximately $1,269.4
million, of which residential customers accounted for 67 percent, commercial 27
percent, and industrial and other contract customers 6 percent.
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 194.6 MMDth for the year ended
December 31, 2007. Gas transported or sold to residential and
commercial customers was 108.4 MMDth representing 56 percent of
throughput. Gas transported or sold to industrial and other contract
customers was 86.2 MMDth representing 44 percent of
throughput. Rates for transporting gas generally provide for the same
margins earned by selling gas under applicable sales tariffs.
The
volume of gas sold is seasonal and 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 Holdings, 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. The Company also 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 2007,
the Company purchased 101,912 MDth volumes of gas at an average cost of $8.14
per Dth, of which approximately 71 percent was purchased through ProLiance and
29 percent was purchased from 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 a 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 $8.14 in 2007, $8.64 in 2006, $9.05 in 2005, $6.92 in 2004, and
$6.36 in 2003.
Electric Utility
Services
At
December 31, 2007, the Company supplied electric service to over 141,000 Indiana
customers, including approximately 122,000 residential, 18,800 commercial, and
200 industrial and other customers. Customer base growth was
approximately 0.5 percent compared to 2006. In addition, the Company
has firm power commitments to nearby 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, 2007, retail and firm wholesale electricity sales
totaled 6,216.5 GWh, resulting in revenues of approximately $448.1
million. Residential customers accounted for 36 percent of 2007
revenues; commercial 25 percent; industrial 31 percent, and municipal and other
8 percent. In addition, the Company sold 921.3 GWh through
optimization activities in 2007, generating revenue, net of purchased power
costs, of $39.8 million.
System
Load
Total
load for each of the years 2003 through 2007 at the time of the system summer
peak, and the related reserve margin, is presented below in MW.
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Date
of summer peak load
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8/08/2007
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8/10/2006
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7/25/2005
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7/13/2004
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8/27/2003
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Total
load at peak (1)
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1,341
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1,325
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1,315
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1,222
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1,272
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Generating
capability
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1,295
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1,351
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1,351
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1,351
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1,351
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Firm
purchase supply
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130
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107
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107
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105
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32
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Interruptible
contracts
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62
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62
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76
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51
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95
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Total
power supply capacity
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1,487
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1,520
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1,534
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1,507
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1,478
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Reserve
margin at peak
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11 | % | 15 | % | 17 | % | 23 | % | 16 | % | ||||||||||
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(1)
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The
total load at peak is increased 25 MW in 2007, 2006, 2005, and 2003 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.
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The
winter peak load for the 2006-2007 season of approximately 961 MW occurred on
December 7, 2006. The prior year winter peak load was approximately
935 MW, occurring on December 20, 2005.
Generating
Capability
Installed
generating capacity as of December 31, 2007, was rated at 1,295
MW. Coal-fired generating units provide 1,000 MW of capacity, and
natural gas or oil-fired turbines used for peaking or emergency conditions
provide 295 MW. Electric generation for 2007 was fueled by coal (98
percent) and natural gas (2 percent). Oil was used only for testing
of gas/oil-fired peaking units. The Company generated approximately
6,873 GWh in 2007. Further information about the Company’s owned
generation is included in "Item 2 Properties".
In
January 2008, the Company requested authority from the IURC to build a 100 MW
gas-fired turbine peaking unit in Gibson County Indiana. If approved, it
would be operational by 2010. The Company discontinued operations of
Culley Unit 1 (50 MW) effective December 31, 2006.
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 3.3 million tons of coal were purchased
for generating electricity during 2007, of which approximately 92 percent 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 2003 through 2007
follows:
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Year
Ended December 31,
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Avg.
Cost Per
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2007
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2006
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2005
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2004
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2003
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Ton
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$ |
40.23
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$ |
37.51
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$ |
30.27
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$ |
27.06
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$ |
24.91
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MWh
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19.78
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18.44
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14.94
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13.06
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11.93
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Firm Purchase
Supply
The
Company maintains a 1.5 percent 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 percent
interest in the OVEC makes available approximately 30 MW of capacity for use in
other operations. The Company purchased approximately 231 GWh from
OVEC in 2007.
The
Company has a capacity contract with Duke Energy Marketing America, LLC. (Duke)
to purchase as much as 100 MW at any time from a power plant located in
Vermillion County, Indiana. The contract ends on December 31,
2009. The Company purchased approximately 17 GWh under this contract
in 2007.
Other Power
Purchases
The
Company also purchases power as needed principally from the MISO to supplement
its generation and firm purchase supply in periods of peak
demand. Volumes purchased principally from the MISO in 2007 totaled
416 GWh.
Interconnections
The
Company has interconnections with Louisville Gas and Electric Company, Duke
Energy Shared 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.
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 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, 2007, over
77,000 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.
On February 4, 2008, the
Company along with the OCC and other interveners filed a settlement agreement
with the PUCO regarding the first two stages of a three
stage plan to exit the
merchant function in the Company’s Ohio service territory. As designed,
the terms and conditions of the plan allow in stage one for a regulator-approved
auction to select qualified wholesale suppliers that will supply gas commodity
to the Company for resale to its customers at auction-determined standard
pricing. In stage two, the Company will no longer sell natural gas
directly to customers; rather a regulator-approved auction will select
state-certified Choice suppliers that will sell gas commodity to customers at
auction-determined standard pricing and the Company will transport that gas
supply to the customers. In the third stage, which is not part of this
application filing, it is contemplated that all of the Company’s Ohio customers
will choose their commodity supplier from state-certified Choice suppliers in
the competitive market. The settlement agreement includes an Exit
Transition Cost rider which, if approved, will allow the Company to recover
costs associated with the transition to this market structure. As the cost
of gas is currently passed through to customers through a regulator approved
recovery mechanism, the impact of exiting the merchant function should not have
a material impact on Company earnings or financial condition. If
the
settlement agreement is approved, the Company’s transition to this market structure
will commence in mid to late 2008.
Regulatory and Environmental
Matters
See “Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s regulatory environment and 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
Holdings, 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
Indiana 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 percent of ProLiance’s profits and losses; however, governance and
voting rights remain at 50 percent for each member; and therefore, the Company
accounts for its investment in ProLiance using the equity method of
accounting. The Company, including its retail gas supply operations,
contracted for 75 percent of its natural gas purchases through ProLiance in
2007.
For the
year ended December 31, 2007, ProLiance’s revenues, including sales to Vectren
companies, exceeded $2.3 billion.
At
December 31, 2007, the pre-tax earnings of ProLiance exceeded 20 percent of
Vectren’s pre-tax earnings. In accordance with Regulation S-X,
paragraph 3-09, ProLiance’s audited financial statements as of and for its
fiscal years ending September 30, 2007, 2006, and 2005, are
included as Exhibit 99.1 to 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 over 161,000
residential and commercial customers opting for choice among energy
providers. Vectren Source generated approximately $168.3 million in
revenues in 2007, up from $162.5 million in 2006. Gas sold
approximated 13,543 MDth in 2007, 12,228 MDth in 2006 and 12,411 MDth in
2005.
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 4.1 million tons in
2007, compared to 4.0 million tons in 2006 and 4.4 million tons in
2005.
In April
2006, Fuels announced plans 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.
Miller and Reliant Services,
LLC
Effective
July 1, 2006, the Company purchased the remaining 50 percent of 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.
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 is also
involved in creating renewable energy projects, including projects to process
landfill gas into usable natural gas. 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.
Other Businesses
The Other
Businesses group includes a variety of wholly owned operations and investments
that have invested in broadband communication services, energy-related
opportunities and services, real estate, and leveraged leases, among other
investments. Major investments at December 31, 2007, include
Haddington Energy Partnerships, two partnerships both approximately 40 percent
owned; and wholly owned subsidiaries, Southern Indiana Properties, Inc. and
Energy Realty, Inc.
The
Company had an approximate 2 percent equity interest and a convertible
subordinated debt investment in Utilicom Networks, LLC
(Utilicom). The Company also had an approximate 19 percent equity
interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to
hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provided 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 produced and sold coal-based synthetic fuel
using Covol technology, and according to US tax law, its members received 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, received
processing fees from synfuel producers unrelated to Pace Carbon for a portion of
its coal production. Under current tax laws, these synfuel related credits
and fees ended on December 31, 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, 2007, the Company and its consolidated subsidiaries had 3,579
employees, of which 2,123 are subject to collective bargaining
arrangements. Of that total, 1,491 employees are Miller
employees.
In July
2007, the Company reached a three-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2010.
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. The agreement
with the International Union of Operating Engineers expires in May
2008. The rest of 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
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 30-year 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 NERC (North American Electric Reliability Corporation), the IURC and
the PUCO. These authorities regulate many aspects of its transmission
and distribution operations, including construction and maintenance of
facilities, operations, and safety, and its gas marketing operations involving
title passage, reliability standards, and future adequacy. In
addition, these regulatory agencies regulate the rates that Vectren’s utilities
can charge customers, the rate of return that Vectren’s utilities are authorized
to earn, and its ability to timely recover gas and fuel costs. 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. As gas costs remain above
historical levels, any
future disallowance might be material to the Company’s operations or financial
condition.
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 and other proposals that would mandate an investment in
renewable energy sources. Any future legislative or regulatory
actions taken to address global climate change or mandate renewable energy
sources 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 and increased
costs to acquire renewable energy sources.
From time to time, Vectren is subject
to material litigation and regulatory proceedings.
From time
to time, the Company, as well as its equity investees such as ProLiance, may be
subject to material litigation and regulatory proceedings including matters
involving compliance with state and federal laws or other
matters. There can be no assurance that the outcome of these matters
will not have a material adverse effect on Vectren’s business, prospects,
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 power purchase 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.
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.
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 a pending Day 3 market, where MISO plans to
provide bid-based regulation and contingency operating reserve markets, it is
difficult to predict near term operational impacts. MISO has
indicated that the Day 3 ancillary services market would begin in June
2008.
The
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 is expected to be significant. As part of its
recent rate case, SIGECO obtained approval to recover costs for certain
transmission projects through its MISO tracker.
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. Margin earned from these activities above or below $10.5
million is shared evenly with customers. These 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, either with 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 and the
Company’s nonutility gas retail supply operations 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; failure
to properly estimate the cost to construct projects; 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
has significant synfuel tax credits subject to IRS audit
The
Company has an 8.3 percent ownership interest in Pace Carbon Synfuels, LP (Pace
Carbon). Pace Carbon produced and sold coal-based synthetic fuel using Covol
technology and, according to US tax law, its members received a tax credit for
every ton of coal-based synthetic fuel sold. Under current tax laws, synfuel
related tax credits and fees ended on December 31, 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. Generally, the statute of
limitations for the IRS to audit a tax return is three years from filing.
Therefore tax credits utilized in 2004 – 2007 are still subject to IRS
examination. However, avenues remain where the IRS could challenge tax credits
of pre-2004 years.
As
a partner of Pace Carbon, Vectren has reflected synfuel tax credits in its
consolidated results from inception through December 31, 2007 of approximately
$99 million, of which approximately $60 million have been generated since 2003.
To date, Vectren has been in a position to utilize or carryforward substantially
all of the credits generated.
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,
operations, financial condition and results of 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 (or negative outlook) in
or withdrawal of Vectren’s credit ratings, or the credit ratings of bond
insurers that insure certain long-term debt of SIGECO, could negatively affect
its ability to access capital and its cost.
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 and Indiana Gas senior unsecured debt
|
Baa1
|
A-
|
|
Utility
Holdings commercial paper program
|
P-2
|
A-2
|
|
SIGECO’s
senior secured debt
|
A-3
|
A
|
The
current outlook of both Standard and Poor’s and Moody’s is stable and both
categorize the ratings of the above securities 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 initiate negative outlooks
thereon, or withdraw Vectren’s ratings or, in each case, the ratings of its
subsidiaries, 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.
SIGECO
has approximately $103 million of tax-exempt adjustable rate long-term debt
where the interest rates on this debt are reset every seven days through an
auction process. In February 2008, significant disruptions occurred in the
overall auction rate debt markets. As a result, many auctions of tax-exempt
debt, including some of those involving SIGECO's auction rate debt, failed as a
result of insufficient order interest from potential investors. These failures
are largely attributable to a lack of liquidity in the market place arising from
downgrades in, and negative watches regarding, credit ratings of monoline
insurers that guarantee the timely repayment of bond principal and interest if
an issuer defaults, as well as from disruptions in the overall financial
markets. Monoline insurer Ambac Assurance Corporation insures the Company's
auction rate long-term debt. As a result of these failed auctions, interest
rates associated with these instruments reset to the maximum rates permitted
under the various debt indentures of 10 percent to 15 percent for the following
week. On a weekly basis, interest expense using these maximum rates is
approximately $200,000 higher than the average weekly interest expense based on
rates experienced during 2007.
Subject to applicable notice
provisions, SIGECO may, at its option, redeem this auction rate debt at par
value plus the accrued and unpaid interest or elect to utilize other interest
rate modes available to it as defined in the various debt indentures. SIGECO is
in the process of providing notice to current holders of this debt that it will
be converted from the auction rate mode into a daily interest rate mode during
March 2008 and the debt will be subject to mandatory tender for purchase on the
conversion date at 100 percent of the principal amount plus accrued interest.
While the Company completes its conversion from the current auction rate mode to
the daily interest rate mode, it may continue to experience increased interest
costs. Following
conversion to the daily mode, SIGECO maintains its options to again convert the
debt to other interest rate modes and remarket it to investors or redeem the
debt and reissue new debt, including the possibility of replacing it with
taxable debt from Utility Holdings.
Anti-takeover 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 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 IBCL) 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 percent 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 percent 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 17.9 BCF of storage
with a maximum peak day delivery capability of 298,579 MMBTU per
day. Indiana Gas’ gas delivery system includes 12,699 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
108,500 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 3,192 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 0.5 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 11.8 BCF
of storage with a maximum peak day delivery capability of 246,080 MMBTU per
day. The Ohio operations’ gas delivery system includes 5,468 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, 2007, was rated at 1,295
MW. SIGECO's coal-fired generating facilities are the Brown Station
with two units of 490 MW of combined capacity, located in Posey County
approximately eight miles east of Mt. Vernon, Indiana; the Culley Station
with two units of
360 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.
SIGECO's
transmission system consists of 926 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 31 substations with an
installed capacity of 5,457 megavolt amperes (Mva). The electric
distribution system includes 4,211 pole miles of lower voltage overhead lines
and 340 trench miles of conduit containing 1,878 miles of underground
distribution cable. The distribution system also includes 98
distribution substations with an installed capacity of 3,002 Mva and 53,456
distribution transformers with an installed capacity of 2,497 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 5 percent of
total assets. The assets of Miller comprise approximately 3
percent 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. 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 2007 and 2006, 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
|
||||||||||
|
2007
|
||||||||||||
|
First
Quarter
|
$ |
0.315
|
$ |
28.80
|
$ |
27.32
|
||||||
|
Second
Quarter
|
0.315
|
30.06
|
26.42
|
|||||||||
|
Third
Quarter
|
0.315
|
28.50
|
24.85
|
|||||||||
|
Fourth
Quarter
|
0.325
|
30.50
|
26.51
|
|||||||||
|
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
|
|||||||||
On January 30, 2008, the board of directors declared a dividend of $0.325 per share, payable on March 3, 2008, to common shareholders of record on February 15, 2008.
As of
January 31, 2008, there were 10,234 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. The
following chart contains information regarding open market purchases made by the
Company to satisfy those plans during the quarter ended December 31,
2007.
|
Period
|
Number
of Shares Purchased
|
Average
Price Paid Per Share
|
Total
Number of Shares Purchased as Part of Publicly Announced
Plans
|
Maximum
Number of Shares That May Be Purchased Under These Plans
|
||||||||||||
|
October
1-31
|
-
|
-
|
-
|
-
|
||||||||||||
|
November
1-30
|
123,706
|
$ |
28.84
|
-
|
-
|
|||||||||||
|
December
1-31
|
-
|
-
|
-
|
-
|
||||||||||||
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 percent of earnings over time. On an annual
basis, this percentage has varied and could continue to vary due to short-term
earnings volatility. The Company has increased its dividend for 48
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)
|
2007
|
2006
|
2005
|
2004
|
2003
|
|||||||||||||||
|
Operating
Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ |
2,281.9
|
$ |
2,041.6
|
$ |
2,028.0
|
$ |
1,689.8
|
$ |
1,587.7
|
||||||||||
|
Operating
income
|
$ |
260.5
|
$ |
220.5
|
$ |
213.1
|
$ |
199.5
|
$ |
196.0
|
||||||||||
|
Net
income
|
$ |
143.1
|
$ |
108.8
|
$ |
136.8
|
$ |
107.9
|
$ |
111.2
|
||||||||||
|
Average
common shares outstanding
|
75.9
|
75.7
|
75.6
|
75.6
|
70.6
|
|||||||||||||||
|
Fully
diluted common shares outstanding
|
76.6
|
76.2
|
76.1
|
75.9
|
70.8
|
|||||||||||||||
|
Basic
earnings per share on common stock
|
$ |
1.89
|
$ |
1.44
|
$ |
1.81
|
$ |
1.43
|
$ |
1.58
|
||||||||||
|
Diluted
earnings per share on common stock
|
$ |
1.87
|
$ |
1.43
|
$ |
1.80
|
$ |
1.42
|
$ |
1.57
|
||||||||||
|
Dividends
per share on common stock
|
$ |
1.27
|
$ |
1.23
|
$ |
1.19
|
$ |
1.15
|
$ |
1.11
|
||||||||||
|
Balance Sheet
Data:
|
||||||||||||||||||||
|
Total
assets
|
$ |
4,296.4
|
$ |
4,091.6
|
$ |
3,868.1
|
$ |
3,586.9
|
$ |
3,353.4
|
||||||||||
|
Long-term
debt, net
|
$ |
1,245.4
|
$ |
1,208.0
|
$ |
1,198.0
|
$ |
1,016.6
|
$ |
1,072.8
|
||||||||||
|
Redeemable
preferred stock
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
0.1
|
$ |
0.2
|
||||||||||
|
Common
shareholders' equity
|
$ |
1,233.7
|
$ |
1,174.2
|
$ |
1,143.3
|
$ |
1,094.8
|
$ |
1,071.7
|
||||||||||
In this
discussion and analysis, the Company analyzes contributions to consolidated
earnings from its Utility Group and Nonutility Group separately since each
operate independently requiring distinct competencies and business strategies,
offers different energy and energy related products and services, and
experiences different opportunities and risks. Nonutility Group
operations are discussed below as primary operations, other operations, and
synfuel-related results. Primary nonutility operations denote areas
of management’s forward looking focus. Tax laws authorizing tax
credits for the production of certain synthetic fuels expired on December 31,
2007, and should not have a material impact on future results.
|
Per
share earnings contributions of the Utility Group, Nonutility Group, and
Corporate and Other are presented. Such per share amounts are based
on the earnings contribution of each group included in Vectren’s
consolidated results divided by Vectren’s basic 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 the groups, but rather represent a direct equity interest in Vectren
Corporation's assets and liabilities as a
whole.
|
|
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 activities of and revenues and cash flows
generated by 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. In addition, there are other operations, referred to
herein as Corporate and Other, that include unallocated corporate expenses
such as advertising and charitable contributions, among other
activities.
|
|
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.
|
|
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)
|
2007
|
2006
|
2005
|
|||||||||
|
Net
income
|
$ |
143.1
|
$ |
108.8
|
$ |
136.8
|
||||||
|
Attributed
to:
|
||||||||||||
|
Utility
Group
|
$ |
106.5
|
$ |
91.4
|
$ |
95.1
|
||||||
|
Nonutility
Group
|
37.0
|
18.1
|
48.2
|
|||||||||
|
Corporate
& Other
|
(0.4 | ) | (0.7 | ) | (6.5 | ) | ||||||
|
Basic
earnings per share
|
$ |
1.89
|
$ |
1.44
|
$ |
1.81
|
||||||
|
Attributed
to:
|
||||||||||||
|
Utility
Group
|
$ |
1.40
|
$ |
1.21
|
$ |
1.26
|
||||||
|
Nonutility
Group
|
0.49
|
0.24
|
0.64
|
|||||||||
|
Corporate
& Other
|
-
|
(0.01 | ) | (0.09 | ) | |||||||
Results
For the
year ended December 31, 2007, reported earnings were $143.1 million, or $1.89
per share, compared to $108.8 million, or $1.44 per share in 2006, and $136.8
million, or $1.81 per share, in 2005. The increase in 2007 earnings
compared to 2006 is primarily attributable to higher gas and electric utility
margins and increased earnings from the sale of wholesale
power. Results also reflect increased earnings from the Company’s
nonutility operations, primarily Energy Infrastructure Services, and increased
synfuel-related results. The decline in 2006 results compared to 2005
is primarily attributable to a decline in synfuel-related results, a charge
related to the settlement of a lawsuit involving ProLiance Holdings, LLC
(ProLiance), and lower wholesale power marketing margins.
Utility
Group
In 2007,
the Utility Group’s earnings were $106.5 million compared to $91.4 million in
2006. The increase resulted from base rate increases in the Vectren
South service territory, the combined impact of residential and commercial usage
and lost margin recovery, favorable weather, and increased wholesale power
marketing margins. The increase was offset somewhat by increased
operating costs including depreciation expense and a lower effective tax rate in
2006.
In 2006
compared to 2005, the decline in Utility Group earnings is primarily the result
of lower wholesale power marketing margins as well as declines in customer
usage, higher depreciation and interest costs. 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 the
Company’s electric and Ohio natural gas service territories which are not
protected by weather normalization mechanisms, management estimates the 2007
margin impact of weather experienced to be $5.5 million favorable compared to
30-year normal temperatures, or $0.04 on a per share basis. In 2006
and 2005 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 and unfavorable $0.04 per share
in 2005. The 2007 and 2006 weather effect is net of normal
temperature adjustment (NTA) mechanism impacts. The NTA was
implemented in the Company’s Indiana natural gas service territories in the
fourth quarter of 2005.
Nonutility
Group
The
Nonutility Group’s 2007 earnings were $37.0 million compared to $18.1 million in
2006 and $48.2 million in 2006. The Company’s primary nonutility
operations contributed earnings of $33.7 million in 2007 compared to $24.5
million in 2006 and $35.3 million in 2005. Primary nonutility
operations are Energy Marketing and Services companies, Coal Mining operations,
and Energy Infrastructure Services companies.
Primary
nonutility group results increased $9.2 million, or $0.12 per
share. The increase was primarily attributable to higher Miller
Pipeline (Miller) earnings and the unfavorable impact of the ProLiance
litigation settlement recorded in the fourth quarter of 2006. The
increased contribution from Miller of $3.8 million is due largely to more large
gas construction projects, pricing increases, and Vectren’s 100 percent
ownership of Miller in 2007. Earnings from Energy Systems Group and
retail gas marketing operations were also favorable year over
year. Operating earnings from ProLiance were down year over year by
$2.0 million as the favorable impact of their increased storage capacity was
more than offset by lower volatility in the wholesale natural gas
markets. Coal Mining earnings were $2.0 million in 2007 compared to
$5.0 million in 2006 primarily due to compliance with new Mine Safety and Health
Administration (MSHA) seal and safety guidelines and the associated lost
production and higher sulfur content from coal mined under the revised mining
plan.
Primary
nonutility business earnings decreased $10.8 million in 2006 compared to
2005. Earnings from ProLiance decreased $12.8 million year over year
due largely to the $6.6 million legal settlement. In addition,
ProLiance achieved record earnings in 2005 due to larger spreads between
financial and physical markets, which resulted from market disruptions caused by
Gulf Coast hurricanes. Energy Infrastructure Services companies,
which include Energy Systems Group and Miller Pipeline contributed additional
earnings of $3.4 million and $1.3 million respectively and offset lower earnings
from Vectren Source and Coal Mining operations.
Results from other nonutility
businesses, which were earnings of $0.3 million in 2007, losses of $1.1 million
in 2006, and income of $1.2 million in 2005, were primarily impacted by the
Company’s broadband investments and its investment in Haddington Energy
Partners. In 2006, the Company sold its investment in SIGECOM, LLC at
a loss of approximately $1.3 million after tax. In 2005, Haddington’s
results include a $3.9 million after tax gain on the sale of an
investment.
In 2007,
the last year of synfuel operations, synfuel-related results generated earnings
of $6.8 million. Of those earnings, which do not continue in 2008 and
beyond, $3.8 million ($5.8 million on a pre tax basis) was contributed to the
Vectren Foundation. Net of that contribution, synfuel-related results
were $3.0 million, or $0.04 per share, in 2007, compared to a loss of $5.3
million, or $0.07 per share, in 2006 and earnings of $11.7 million or $0.15 per
share in 2005. In 2006, synfuel-related activity includes a $5.7
million after tax impairment charge related to the Company’s investment in Pace
Carbon Synfuels LP. The Foundation contribution is included in Other operating expenses in
the Consolidated Statements of Income.
Other
Operations
Corporate
and Other reported a loss of $0.09 per share in 2005 due principally to a $6.5
million, or $4.2 million after tax, contribution to the Vectren Foundation,
which is also recorded in Other operating
expenses.
Dividends
Dividends
declared for the year ended December 31, 2007 were $1.27 per share compared to
$1.23 in 2006 and $1.19 per share in 2005. In October 2007, the
Company’s board of directors increased its quarterly dividend to $0.325 per
share from $0.315 per share. The increase marks the 48th consecutive year
Vectren and predecessor companies’ have increased annual dividends
paid.
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.
Results of Operations of the
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 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. Utility operating results before certain
intersegment eliminations and reclassifications for the years ended December 31,
2007, 2006, and 2005, follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In millions, except per share
data)
|
2007
|
2006
|
2005
|
|||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ |
1,269.4
|
$ |
1,232.5
|
$ |
1,359.7
|
||||||
|
Electric
utility
|
487.9
|
422.2
|
$ |
421.4
|
||||||||
|
Other
|
1.7
|
1.8
|
$ |
0.7
|
||||||||
|
Total operating
revenues
|
1,759.0
|
1,656.5
|
1,781.8
|
|||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
847.2
|
841.5
|
973.3
|
|||||||||
|
Cost
of fuel & purchased power
|
174.8
|
151.5
|
144.1
|
|||||||||
|
Other
operating
|
266.1
|
239.0
|
241.3
|
|||||||||
|
Depreciation
& amortization
|
158.4
|
151.3
|
141.3
|
|||||||||
|
Taxes
other than income taxes
|
68.1
|
64.2
|
65.2
|
|||||||||
|
Total
operating expenses
|
1,514.6
|
1,447.5
|
1,565.2
|
|||||||||
|
OPERATING
INCOME
|
244.4
|
209.0
|
216.6
|
|||||||||
|
Other
income - net
|
9.4
|
7.6
|
5.9
|
|||||||||
|
Interest
expense
|
80.6
|
77.5
|
69.9
|
|||||||||
|
INCOME BEFORE INCOME
TAXES
|
173.2
|
139.1
|
152.6
|
|||||||||
|
Income
taxes
|
66.7
|
47.7
|
57.5
|
|||||||||
|
NET
INCOME
|
$ |
106.5
|
$ |
91.4
|
$ |
95.1
|
||||||
|
CONTRIBUTION TO VECTREN BASIC
EPS
|
$ |
1.40
|
$ |
1.21
|
$ |
1.26
|
||||||
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. Electric Utility margin is calculated as Electric Utility revenues
less Cost of fuel &
purchased power. These measures exclude Other operating expenses,
Depreciation and amortization, and Taxes other than income
taxes, which are included in the calculation of operating
income. 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.
Sales of
natural gas and electricity to residential and commercial customers are seasonal
and are impacted by weather. Trends in average use among natural gas
residential and commercial customers have tended to decline in recent years as
more efficient appliances and furnaces are installed and the price of natural
gas has increased. Normal temperature adjustment (NTA) and lost margin
recovery mechanisms largely mitigate the effect on Gas Utility margin that would
otherwise
be caused
by variations in volumes sold due to weather and changing consumption
patterns. Indiana Gas’ territory has both an NTA since 2005 and lost
margin recovery since December 2006. SIGECO’s natural gas territory has an
NTA since 2005, and lost margin recovery began when new base rates went into
effect August 1, 2007. The Ohio service territory has lost margin recovery
since October 2006, but does not have an NTA mechanism. SIGECO’s electric
service territory does not have an NTA mechanism but has recovery of past demand
side management costs.
Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses. Expenses subject to tracking mechanisms include Ohio bad debts and percent of income payment plan expenses, Indiana gas pipeline integrity management costs, and costs to fund Indiana energy efficiency programs. Certain operating costs associated with operating environmental compliance equipment were also tracked prior to their recovery in base rates that went into effect on August 15, 2007. The August SIGECO rate orders also provide for the tracking of MISO revenues and costs, as well as the gas cost component of bad debt expense and unaccounted for gas. 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)
|
2007
|
2006
|
2005
|
|||||||||
|
Gas
utility revenues
|
$ |
1,269.4
|
$ |
1,232.5
|
$ |
1,359.7
|
||||||
|
Cost
of gas sold
|
847.2
|
841.5
|
973.3
|
|||||||||
|
Total gas utility
margin
|
$ |
422.2
|
$ |
391.0
|
$ |
386.4
|
||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ |
357.1
|
$ |
330.2
|
$ |
333.2
|
||||||
|
Industrial
customers
|
48.3
|
48.0
|
48.3
|
|||||||||
|
Other
customers
|
16.8
|
12.8
|
4.9
|
|||||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
108.4
|
97.7
|
112.9
|
|||||||||
|
Industrial
customers
|
86.2
|
84.9
|
87.2
|
|||||||||
|
Total sold & transported
volumes
|
194.6
|
182.6
|
200.1
|
|||||||||
Gas Utility margins were $422.2 million for the year ended December 31, 2007, an increase of $31.2 million compared to 2006. Residential and commercial customer usage, including lost margin recovery, increased margin $13.3 million year over year. For all of 2007, Ohio weather was 6 percent warmer than normal, but approximately 6 percent colder than the prior year and resulted in an estimated increase in margin of approximately $2.0 million compared to 2006. Margin increases associated with the Vectren South base rate increase, effective August 1, 2007, were $3.3 million. Recovery of gas storage carrying costs in Ohio was $2.3 million. Lastly, operating costs, including revenue and usage taxes recovered dollar-for-dollar in margin, increased gas margin $10.3 million year over year. During 2007, the company resolved all remaining issues related to a 2005 disallowance by the PUCO of gas costs incurred by the Ohio utility operations, resulting in an additional charge of $1.1 million. The average cost per dekatherm of gas purchased for the year ended December 31, 2007, was $8.14 compared to $8.64 in 2006 and $9.05 in 2005.
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 NTA implemented in 2005 in the Company’s Indiana service
territories, and the lost margin recovery authorizations 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.
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)
|
2007
|
2006
|
2005
|
|||||||||
|
Electric
utility revenues
|
$ |
487.9
|
$ |
422.2
|
$ |
421.4
|
||||||
|
Cost
of fuel & purchased power
|
174.8
|
151.5
|
144.1
|
|||||||||
|
Total electric utility
margin
|
$ |
313.1
|
$ |
270.7
|
$ |
277.3
|
||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ |
194.7
|
$ |
162.9
|
$ |
170.8
|
||||||
|
Industrial
customers
|
75.0
|
70.2
|
66.9
|
|||||||||
|
Municipal
& other customers
|
21.8
|
24.0
|
19.8
|
|||||||||
|
Subtotal: Retail & firm
wholesale
|
$ |
291.5
|
$ |
257.1
|
$ |
257.5
|
||||||
|
Asset
optimization
|
$ |
21.6
|
$ |
13.6
|
$ |
19.8
|
||||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
3,042.9
|
2,789.7
|
2,933.2
|
|||||||||
|
Industrial
customers
|
2,538.5
|
2,570.4
|
2,575.9
|
|||||||||
|
Municipal
& other customers
|
635.1
|
644.4
|
689.9
|
|||||||||
|
Total retail & firm
wholesale volumes sold
|
6,216.5
|
6,004.5
|
6,199.0
|
|||||||||
Retail & Firm Wholesale
Margin
Electric
retail and firm wholesale utility margins was $291.5 million for the year ended
December 31, 2007. This represents an increase over the prior year of
$34.4 million, respectively. Management estimates the year over year
increases in usage by residential and commercial customers due to weather to be
$11.8 million. The base rate increase that went into effect on August
15, 2007, produced incremental margin of $17.9 million. During 2007,
cooling degree days were 33 percent above normal compared to 5 percent below
normal in 2005. Recovery of pollution control investments and
expenses increased margin $5.5 million year over year.
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 below normal heating
weather). In 2005, cooling degree days were 9 percent above
normal.
Margin from Asset Optimization
Activities
Periodically,
generation capacity is in excess of that needed to serve native load and firm
wholesale customers. The Company markets and sells this unutilized
generating and transmission capacity to optimize the return on its owned
assets. A majority of the margin generated from these activities is
associated with wholesale off-system sales, and substantially all off-system
sales occur into the MISO Day Ahead market.
Asset
optimization activity is comprised of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Off-system
sales
|
$ |
16.9
|
$ |
14.2
|
$ |
15.3
|
||||||
|
Transmission
system sales
|
4.7
|
3.5
|
4.5
|
|||||||||
|
Other
|
-
|
(4.1 | ) |
-
|
||||||||
|
Total asset
optimization
|
$ |
21.6
|
$ |
13.6
|
$ |
19.8
|
||||||
For the
year ended December 31, 2007, net asset optimization margins were $21.6 million,
which represents an increase of $8.0 million, compared to 2006. The
increase is primarily due to losses on financial contracts experienced in 2006
and higher fourth quarter wholesale prices. Margins in 2006 decreased
$6.2 million when compared to 2005 primarily due to the financial contract
losses experienced in 2006 and lower volumes sold off system. In
2006, the availability of excess capacity was reduced by scheduled outages
associated with the installation of environmental compliance
equipment. Off-system sales totaled 948.9 GWh in 2007, compared to
889.4 GWh in 2006 and 1,208.1 GWh in 2005.
Utility Group Operating
Expenses
Other Operating
For the
year ended December 31, 2007, Other operating expenses were
$266.1 million, which represents an increase of $27.1 million, compared to
2006. Operating costs recovered dollar for dollar in margin,
including costs funding new Indiana energy efficiency programs, increased $9.5
million year over year. Increases in operating costs associated with
lost margin recovery and conservation initiatives that are not directly
recovered in margin were $1.3 million year over year. Costs directly
attributable to the Vectren South rate cases, including amortization of prior
deferred costs, totaled $3.6 million in 2007. Expenses in 2006 are
offset by the gain on the sale of a storage asset of approximately $4.4
million. The remaining increases are primarily due to increased wage
and benefit costs.
The 2006
$4.4 million gain on sale of a storage asset, partially offset by higher
electric generation chemical costs and bad debt expense in the Company’s Indiana
service territories were the primary factors decreasing operating expense in
2006 compared to 2005.
Depreciation &
Amortization
Depreciation
expense increased $7.1 million in 2007 compared to 2006 and $10.0 million in
2006 compared to 2005. The increases were primarily due to increased
utility plant in service. Expense in 2007 also includes $1.8 million
of amortization associated with prior electric demand side management costs
pursuant to the August 15, 2007,
electric base rate order.
Taxes Other Than Income
Taxes
Taxes
other than income taxes increased $3.9 million in 2007 compared to 2006 and
decreased $1.0 million in 2006 compared 2005. The fluctuations are
primarily attributable to variations in utility receipts, excise, and usage
taxes. These variations resulted primarily from volatility in
revenues and gas volumes sold. In 2007 and 2006, property taxes also
increased due to increased plant in service.
Other
Income-Net
Other-net reflects income of
$9.4 million in 2007 compared to $7.6 million in 2006 and $5.9 million in
2005. The increases relate primarily to the capitalization of funds
used during construction due to increased capital spending and higher interest
income.
Utility Group Interest
Expense
In 2007,
interest expense increased $3.1 million compared to 2006 and increased $7.6
million in 2006 compared to 2005. The increases are primarily driven
by rising interest rates during the period and are also impacted by higher
levels of short-term borrowings.
The 2007
increase was mitigated somewhat by the full impact of financing transactions
completed in October 2006 in which approximately $93 million in debt related
proceeds were raised and used to retire debt with a higher interest
rate. Interest costs in 2006 reflect 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.
Utility Group Income
Taxes
Federal
and state income taxes
increased $19.0 million in 2007 compared to 2006 and decreased $9.8 million in
2006 compared to 2005. The changes are impacted primarily by
fluctuations in pre-tax income and a lower effective tax rate in
2006.
The lower
effective tax rate in 2006 primarily relates to 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.
Clean Air/Climate
Change
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. However, on February 8, 2008, the US Court of Appeals for the
District of Columbia vacated the federal CAMR regulations. At this
time it is uncertain how this decision will affect Indiana’s recently finalized
CAMR implementation program.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990 and to further
comply with CAIR and CAMR of 2005, SIGECO has received authority from the IURC
to invest in clean coal technology. Using this authorization, SIGECO
invested approximately $258 million in Selective Catalytic Reduction (SCR)
systems at its coal fired generating stations. SCR technology is the most
effective method of reducing NOx emissions where high removal efficiencies are
required. To further reduce particulate matter emissions, the Company
invested approximately $49 million in a fabric filter at its largest generating
unit (287 MW). These investments were included in rate base for purposes
of determining new base rates that went into effect on August 15, 2007, (See
Rate and Regulatory Matter Section). Prior to being included in base
rates, return on investments made and recovery of related operating expenses
were recovered through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber at its
generating facility that is jointly owned with ALCOA (the Company’s portion is
150 MW). The order, as
updated with an increased spending level, allows SIGECO to recover an
approximate 8 percent return on up to $92 million, excluding
AFUDC, in
capital investments through a rider mechanism which is updated every six months
for actual costs incurred. The Company may file periodic updates with the
IURC requesting modification to the spending authority. As of December 31,
2007, the Company has invested approximately $53 million in this
project. The Company expects the SO2 scrubber will be
operational in 2009. At that time, operating expenses including
depreciation expense associated with the scrubber will also be recovered through
a rider mechanism.
Once the
SO2 scrubber is
operational, SIGECO’s coal fired generating fleet will be 100 percent scrubbed
for SO2 and 90 percent
controlled for NOx. The use of SCR technology positions the Company
to be in compliance with the CAIR deadlines specifying reductions in NOx
emissions by 2009 and further reductions by 2015. Not only does SIGECO's
investments in scrubber, SCR and fabric filter technology position it to comply
with reductions described in the original 2005 mercury emission regulations and
Indiana’s current CAMR implementation plans, it will also likely comply with
more stringent mercury reductions that might follow from revised
regulations.
If
legislation requiring reductions in carbon dioxide and other greenhouse gases or
mandating energy from renewable sources is adopted, such regulation could
substantially affect both the costs and operating characteristics of the
Company’s fossil fuel generating plants and nonutility coal mining
operations. At this time and in the absence of final legislation,
compliance costs and other effects associated with reductions in greenhouse gas
emissions or obtaining renewable energy sources remain
uncertain.
SIGECO is
studying renewable energy alternatives, and on April 9, 2007, filed a green
power rider in order to allow customers to purchase green power and to obtain
approval of a contract to purchase 30 MW of power generated by wind
energy. The wind contract has been approved. Future
filings with the IURC with regard to new generation and/or further environmental
compliance plans will include evaluation of potential carbon
requirements.
Environmental Remediation
Efforts
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
contaminants 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. Indiana Gas submitted the remainder 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.
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 $21 million.
The
estimated accrued costs are limited to Indiana Gas’ 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 percent and 50
percent. With respect to insurance coverage, Indiana Gas has received
and recorded settlements from all known insurance carriers under insurance
policies in effect when these plants were in operation in an aggregate amount
approximating $20 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 October 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 in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has 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 and/or related to the site subject to the May 2007
lawsuit. 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 $8
million. With respect to insurance coverage, SIGECO has received and
recorded settlements from insurance carriers under insurance policies in effect
when these sites were in operation in an aggregate amount approximating the
costs it expects to incur.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites 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 and those costs
may not be subject to PRP or insurance recovery.
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 could be requested by the USEPA at some
future date.
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.
Gas rates
in Indiana contain a gas cost adjustment (GCA) clause, and 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. 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. The
current benchmark expires in March 2008. A settlement agreement
between the Company and the OUCC to modify and extend the benchmark is awaiting
IURC action. An order is expected during the first quarter of
2008.
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. The
Company has not surpassed the limits of the earnings test in the recent
past.
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
its Vectren North gas rate case. The order provided for a base rate
increase of $16.3 million and an ROE of 10.2 percent, with an overall rate of
return of 7.8 percent on rate base of approximately $793 million. The
settlement also provides for the recovery of $10.6 million of costs through
separate cost recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $20 million
and the treatment cannot extend beyond four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity
expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved its Vectren
South electric rate case. The settlement agreement provides for an
approximate $60.8 million electric rate increase to cover the Company’s cost of
system growth, maintenance, safety and reliability. The settlement
provides for, among other things: recovery of ongoing costs and deferred costs
associated with the MISO; operations and maintenance (O&M) expense increases
related to managing the aging workforce, including the development of expanded
apprenticeship programs and the creation of defined training programs to ensure
proper knowledge transfer, safety and system stability; increased O&M
expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by Vectren’s sharing equally with
customers any profit earned above or below $10.5 million of wholesale power
margin; recovery of and return on the investment in past demand side management
programs to help encourage conservation during peak load periods; timely
recovery of the Company’s investment in certain new electric transmission
projects that benefit the MISO infrastructure; an overall rate of return of 7.32
percent on rate base of approximately $1,044 million and an allowed return on
equity (ROE) of 10.4 percent. The increase in Electric Utility margin as a
result of this order totaled $17.9 million in 2007.
Vectren South (SIGECO) Gas
Base Rate Order Received
On August
1, 2007, the Company received an order from the IURC which approved its Vectren
South gas rate case. The order provided for a base rate increase of $5.1
million and an ROE of 10.15 percent, with an overall rate of return of 7.20
percent on rate base of approximately $122 million. The settlement
also provides for the recovery of $2.6 million of costs through separate cost
recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $3 million
and the treatment cannot extend beyond three years on each project.
With this
order, the company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity expense.
The increase in Gas Utility
margin as a result of this order totaled $3.3 million in
2007.
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Case Filing
In November 2007, the Company
filed with the PUCO a request for an increase in its base rates and charges for
VEDO’s distribution business in its 17-county service area in west
central Ohio. The filing indicates that an increase in base
rates of approximately $27 million is necessary to cover the ongoing cost of
operating, maintaining and expanding the approximately 5,200-mile distribution
system used to serve 318,000 customers.
In
addition, the Company is seeking to increase the level of the monthly service
charge as well as extending the lost margin recovery mechanism currently in
place to be able to encourage customer conservation and is also seeking approval
of expanded conservation-oriented programs, such as rebate offerings on
high-efficiency natural gas appliances for existing and new home construction,
to help customers lower their natural gas bills. The Company is also
seeking approval of a multi-year bare steel and cast iron capital replacement
program.
The Company anticipates an order
from the PUCO in late 2008.
-29-
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 proposed 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. These mechanisms are 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 that provides for a
five-year energy efficiency program. It allows the Company’s Indiana
utilities to recover a majority of the costs of promoting the conservation of
natural gas through conservation trackers that work in tandem with a lost margin
recovery mechanism. The order was implemented in the North service
territory in December 2006, and provides for recovery of 85 percent of the
difference between weather normalized revenues actually collected by the Company
and the revenues approved in the Company’s most recent rate
case. Energy efficiency programs began in the North gas territory in
December 2006. A similar approach regarding lost margin recovery
commenced in the South gas territory on August 1, 2007, as the new base rates
went into effect, allowing for recovery of 100 percent of the difference between
weather normalized revenues collected and the revenues approved in that rate
case. The recent Vectren North base rate order also allows for full
recovery of the difference between weather normalized revenues collected by the
Company and the revenues provided for in that settlement, superseding the
original December 2006 order. While
most expenses associated with these programs are recoverable, in the first
program year the Company incurred $0.9 million in program costs without
recovery, of which $0.8 million was expensed in 2007 and, in addition
contributed $0.2 million in assets that are being depreciated over the term of
the program without recovery.
Ohio
In June
2007, the Public Utilities Commission of Ohio (PUCO) approved a settlement that
provides for the implementation of a lost margin recovery mechanism and a
related conservation program for the Company’s Ohio operations. This
order confirms the guidance the PUCO previously provided in a September 2006
decision. The conservation program, as outlined in the September 2006
PUCO order and as affirmed in this order, provides for a two year, $2 million
total conservation program to be paid 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. Approximately 60 percent of the Company’s Ohio customers are
eligible for the conservation programs. The Ohio Consumer Counselor
(OCC) and another intervener requested a rehearing of the June 2007 order and
the PUCO granted that request in order to have additional time to consider the
merits of the request. In accordance with accounting authorization
previously provided by the PUCO, the Company began recognizing the impact of the
September 2006 order on October 1, 2006, and has recognized cumulative revenues
of $4.6 million, of which $3.3 million was recorded in 2007. The OCC
appealed the PUCO’s accounting authorization to the Ohio Supreme Court, but that
appeal has been dismissed as premature pending the PUCO’s consideration of
issues raised in the OCC’s request for rehearing. Since October 1,
2006, the Company has been ratably accruing its $2 million
commitment.
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.
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. The Company is typically in a net sales position with
MISO and is only occasionally in a net purchase position. Net positions
are determined on an hourly basis. When the Company is a net seller such
net revenues are included in Electric Utility revenues and when the
Company is a net purchaser such net purchases are included in Cost of fuel and purchased power. The Company also
receives transmission revenue that results from other members’ use of the
Company’s transmission system. These revenues are also included in
Electric Utility revenues.
Pursuant
to an order from the IURC received in December 2001, certain MISO startup costs
(referred to as Day 1 costs) were deferred, and those deferred costs are now
being recovered through base rates that went into effect on August 15,
2007. On June 1, 2005, Vectren, together with three other Indiana
electric utilities, received regulatory authority from the IURC to recover fuel
related costs and to defer 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. During
2006, the IURC reaffirmed the definition of certain costs as fuel related; the
Company is following those guidelines. Other MISO fuel related and
non-fuel related administrative costs were deferred, and those deferred costs
are now being recovered through base rates that went into effect on August 15,
2007. The IURC order authorizing new base rates also provides for a
tracking mechanism associated with ongoing MISO-related costs and transmission
revenues.
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 a pending Day 3 market, where MISO plans to
provide bid-based regulation and contingency operating reserve markets, it is
difficult to predict near term operational impacts. MISO has
indicated that the Day 3 ancillary services market would begin in June
2008.
The 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 is expected to be significant. The Company will timely
recover its investment in certain new electric transmission projects that
benefit the MISO infrastructure at a FERC approved rate of return.
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 percent 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 is adjusted using the NTA. Revenues
attributable to this order were $4.5 million in 2007 and $13.6 million in 2006
while a downward adjustment to revenues of $1.6 million resulted 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.
SIGECO’s
portion of its commitment ceased in August 2007, and
Indiana Gas’ portion of the commitment ceased on February 14,
2008.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
VEDO Base Rate Increase in
2005
On April
13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas
distribution business. The base rate change was implemented on April
14, 2005 and provide for the recovery of some level of on-going costs to comply
with the Pipeline Safety Improvement Act of 2002.
Gas Cost Recovery (GCR)
Audit Proceedings
In 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 October 2002 and in
2006, an additional $0.8 million was disallowed related to the audit period
ending October 2005. The initial audit period provided the PUCO staff its
initial review of the portfolio administration arrangement between VEDO and
ProLiance. Since November 1, 2005, the Company has used a provider other
than ProLiance for these services.
Through a
series of rehearings and appeals, including action by the Ohio Supreme Court in
the first quarter of 2007, the Company was required to refund $8.6 million to
customers. In total, the Company has reflected $6.2 million in Cost of gas sold related to
this matter, of which $1.1 million, $4.1 million and $1.0 million were recorded
in 2007, 2005, and 2003, respectively. The impact of the
disallowance includes a sharing of the ordered refund by Vectren’s partner in
ProLiance. As of December 31, 2007, all amounts have been refunded to
customers.
Results of Operations of the
Nonutility Group
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 provides performance contracting and renewable
energy services. There are also other businesses that invest in
energy-related opportunities and services, real estate, and leveraged leases,
among other investments. In addition, the Company has in the past
invested in projects that generated synfuel tax credits and processing fees
relating to the production of coal-based synthetic fuels. The
Nonutility Group supports the Company’s regulated utilities pursuant to service
contracts by providing natural gas supply services, coal, infrastructure
services, and other services. Nonutility Group earnings for the years
ended December 31, 2007, 2006, and 2005, follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In millions, except per share
amounts)
|
2007
|
2006
|
2005
|
|||||||||
|
NET
INCOME
|
$ |
37.0
|
$ |
18.1
|
$ |
48.2
|
||||||
|
CONTRIBUTION TO VECTREN BASIC
EPS
|
$ |
0.49
|
$ |
0.24
|
$ |
0.64
|
||||||
|
NET
INCOME ATTRIBUTED TO:
|
||||||||||||
|
Energy Marketing & Services
|
$ |
22.3
|
$ |
14.9
|
$ |
29.7
|
||||||
|
Mining
Operations
|
2.0
|
5.0
|
5.3
|
|||||||||
|
Energy Infrastructure Services
|
9.4
|
4.6
|
0.3
|
|||||||||
|
Other
Businesses
|
0.3
|
(1.1 | ) |
1.2
|
||||||||
|
Synfuels-related
|
3.0
|
(5.3 | ) |
11.7
|
||||||||
Energy Marketing & Services
Energy
Marketing and Services is comprised of the Company’s wholesale and retail gas
marketing and energy management businesses. For the year ended
December 31, 2007, Energy Marketing and Services, inclusive of holding company
costs, earned $22.3 million compared to $14.9 million in 2006 and $29.7 million
in 2005.
ProLiance
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 Indiana 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 percent of ProLiance’s
profits and losses; however, governance and voting rights remain at 50
percent 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
provided the primary earnings contribution, which totaled $22.9 million in 2007
compared to $18.3 million in 2006 and $29.7 million in 2005. Results
in 2006 contain a $6.6 million after tax charge associated with the settlement
of a lawsuit which originated from a dispute over a contractual relationship
with Huntsville Utilities during 2000 – 2002. In 2007, increased
earnings from greater storage capacity were offset by lower volatility in the
wholesale natural gas markets. Earnings in 2005 increased
significantly due to larger spreads between financial and physical markets,
which resulted from market disruptions caused by Gulf Coast
hurricanes. ProLiance’s storage capacity was 40 Bcf at December 31,
2007 compared to 35 Bcf at the end of 2006 and 33 Bcf at the end of
2005. Firm storage capacity will increase to 45 Bcf in early 2008 and
to 49 Bcf by the end of 2008. The expected increase in storage
capacity coupled with an assumed return to market volatility should favorably
impact ProLiance’s results in 2008.
Regulatory
Matter
ProLiance
self reported to the Federal Energy Regulatory Commission (FERC or the
Commission) in October 2007 possible non-compliance with the Commission’s
capacity release policies. ProLiance has taken corrective actions to
assure that current and future transactions are compliant. ProLiance is
committed to full regulatory compliance and is cooperating fully with the FERC
regarding these issues. ProLiance is unable to predict the outcome of any
FERC action.
Vectren
Source
Vectren
Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural
gas and other related products and services to customers opting for choice among
energy providers. Vectren Source earned approximately $1.2 million in
2007, compared to a loss of $0.4 million in 2006 and earnings of $0.9 million in
2005. The increase in earnings is primarily due to lower marketing
costs in 2007 and extremely mild weather in 2006. Vectren Source’s
customer count at December 31, 2007 was approximately 161,000 as compared to the
prior year end count of nearly 150,000.
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 operations, inclusive of holding company costs, earned approximately $2.0
million in 2007 compared to $5.0 million in 2006 and $5.3 million in
2005. The decline in earnings in 2007 is primarily due to the effects
of compliance with revised Mine Safety and Health Administration (MSHA) seal
guidelines and the associated lost production and higher sulfur content from
coal mined under a revised mining plan. These decreases are offset
somewhat by reduced operating costs from highwall mining at the Cypress Creek
surface mine. Mining Operations’ 2006 earnings were generally flat
compared to 2005. Higher revenue and tax benefits from depletion were
offset by unfavorable geologic conditions, the rising costs of commodities used
in operations, and high sulfur content. The Company produced 4.1
million tons of coal in 2007, compared to 4.0 million tons in 2006 and 4.4
million tons in 2005. Earnings in 2008 from Coal Mining operations
are expected to increase due to price increases of 4 to 5 percent, the return to
full production at Prosperity mine, and process improvements that mitigate
impacts from increased MSHA inspections.
In April
2006, Fuels announced plans to open two new underground mines near Vincennes,
Indiana. Construction is progressing as planned and, 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. Through December 31, 2007, the Company has made investments
totaling $21.9 million in the new mines.
Energy Infrastructure
Services
Energy
Infrastructure Services provides underground construction and repair to utility
infrastructure through Miller Pipeline Corporation (Miller) and performance
contracting and renewable energy services through Energy Systems Group, LLC
(ESG). Inclusive of holding company costs, Energy Infrastructure’s
operations contributed earnings of $9.4 million in 2007 compared to $4.6 million
in 2006 and $0.3 million in 2005.
Miller
Pipeline
Miller’s
2007 earnings were $6.1 million in 2007 compared to $2.3 million in 2006 and
$0.9 in 2005. The increase in Miller’s earnings contribution is
primarily due to more large gas construction projects and pricing
increases. Vectren’s 100 percent ownership of Miller effective July
1, 2006 has also contributed to the increase. Earnings in 2008 are
likely to be impacted by expected growth in Miller’s large customers’ aging
infrastructure programs, including pipeline integrity, bare steel/cast iron
replacement, and riser replacement work.
Effective
July 1, 2006, the Company purchased the remaining 50 percent ownership in
Miller, making Miller a wholly owned subsidiary. Prior to this
transaction, Miller was a 50 percent 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 has not been material to the overall financial statements,
consolidating Miller resulted in, among other impacts, increases in Nonutility revenue totaling
$105.7 million in 2007 compared to 2006 and $77.6 million
in 2006 compared to 2005; and increases in Other operating expense
totaling $90.9 million in 2007 compared to 2006 and $60.8 million in 2006
compared to 2005.
During
2006, the Company exited the meter reading and line locating businesses, which
it had previously provided through Reliant Services, LLC.
Energy Systems
Group
ESG’s
2007 earnings were $4.0 million in 2007 compared to $3.1 million in 2006 and a
loss of $0.4 million in 2005. The increases are primarily due to
higher revenues. At December 31, 2007, ESG’s backlog was $52 million,
compared to $68 million at December 31, 2006. The national focus on a
comprehensive energy strategy as evidenced by the new Energy Independence and
Security Act of 2007 is likely to favorably impact ESG’s earnings in 2008 and
beyond.
Other Businesses
The Other
Businesses Group includes a variety of operations and investments including
investments in the Haddington Energy Partnerships (Haddington) which are
accounted for using the equity method. The earnings impact of exiting
the broadband business is also included in Other Businesses.
Other
Businesses reported earnings of $0.3 million compared to a net loss of $1.1
million in 2006 and net income of $1.2 million in 2005. Results for
2006 reflect a loss on the sale of SIGECOM, LLC (SIGECOM). In
2005, Haddington
sold their investments 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. The 2005 Haddington gain was partially offset by a
$1.5 million after tax charge associated with the Company’s broadband consulting
business, which has since ceased operations.
Sale of Interest in
SIGECOM
SIGECOM
provided broadband services, such as cable television, high-speed internet, and
advanced local and long distance phone services, to the greater Evansville,
Indiana area. 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 includes the
settlement of notes receivable, approximated $45 million and were received in
2007.
Synfuel-Related
Activity
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, received processing fees from synfuel producers unrelated to Pace Carbon
for a portion of its coal production. The tax law authorizing synfuel
related credits and fees expired on December 31, 2007.
The
Internal Revenue Service issued private letter rulings, which concluded 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. Generally, the statute
of limitations for the IRS to audit a tax return is three years from filing.
Therefore tax credits utilized in 2004 – 2007 are still subject to IRS
examination. However, avenues remain where the IRS could challenge tax credits
of pre-2004 years.
As a
partner of Pace Carbon, Vectren has reflected synfuel tax credits in its
consolidated results from inception through December 31, 2007 of approximately
$99 million, of which approximately $60 million have been generated since 2003.
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 has an Alternative Minimum Tax (AMT) credit carryforward of
approximately $35.7 million at December 31, 2007.
Synfuel
tax credits were only available when the price of oil was less than a base price
specified by the Internal Revenue Code, as adjusted for inflation. The
Company estimates that high oil prices caused a 74 percent phase out in
2007. Therefore, of the $23.1 million tax credits generated in 2007,
only $6.0 million are reflected as a reduction to the Company’s income tax
expense. In 2006 high oil prices resulted in a 35 percent phase out
of synfuel tax credits. Of the $21.5 million tax credits generated in
2006, only $14.0 million were reflected as a reduction to the Company’s income
tax expense.
Since
2005, the Company executed several financial contracts to hedge oil price
risk. Income statement activity associated with these contracts was a
gain of $13.4 million in 2007, a loss of $4.7 million in 2006 and a loss of $1.9
million in 2005. This activity is primarily reflected in Other-net. Impairment
charges related to the investment in Pace Carbon approximating $9.5 million were
recorded in Other-net
in 2006.
The
investment in Pace Carbon resulted in losses reflected in Equity in earnings of unconsolidated
affiliates totaling $20.0 million in 2007, $17.8 million in 2006, and
$15.7 million in 2005. Synfuel-related results, inclusive of those
losses and their related tax benefits as well as the tax credits and other
related activity, were earnings of $6.8 million in 2007, compared to a loss of
$5.3 million in 2006 and earnings of $11.7 million in 2005. Of those
earnings, which do not continue beyond 2007, $3.8 million ($5.8 million pre tax)
was contributed to the Vectren Foundation in 2007. Net of that
contribution, synfuel-related results were $3.0 million in 2007.
Impact of Recently Issued
Accounting Guidance
FIN 48
On
January 1, 2007, the Company adopted 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.
At
adoption, the total amount of gross unrecognized tax benefits was $11.6
million. The accumulation of this amount resulted in an adjustment to
beginning Retained earnings
of $0.1 million and to Goodwill of $0.2 million.
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. However, in December 2007, the FASB issued
proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). This proposed FSP partially defers the
effective date of Statement 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of this FSP. The Company will adopt SFAS 157 on January 1, 2008,
except as it applies to those nonfinancial assets and nonfinancial liabilities
as noted in proposed FSP FAS 157-b. The partial adoption of SFAS 157
will not have a material impact on our financial position, results of operations
or cash flows.
SFAS No. 159
In
February 2007, the FASB issued Statement No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115 (SFAS 159). SFAS 159 permits entities to measure
many financial instruments and certain other items at fair
value. Items eligible for the fair value measurement option include:
financial assets and financial liabilities with certain exceptions; firm
commitments that would otherwise not be recognized at inception and that involve
only financial instruments; nonfinancial insurance contracts and warranties that
the insurer can settle by paying a third party to provide those goods or
services; and host financial instruments resulting from separation of an
embedded financial derivative instrument from a nonfinancial hybrid
instrument. The fair value option may be applied instrument by
instrument, with few exceptions, is an irrevocable election and is applied only
to entire instruments. The Company will adopt SFAS 159 on January 1,
2008, and does not expect that adoption will have a material impact on its
financial statements and results of operations.
SFAS 141 (Revised
2007)
In
December 2007, the FASB issued SFAS 141, Business Combinations (SFAS
141). SFAS 141 establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141 applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. SFAS 141 applies prospectively to
business combinations with an acquisition date on or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. Early adoption is not permitted. The Company will adopt
SFAS 141 on January 1, 2009, and because the provisions of this standard are
applied prospectively, the impact to the Company cannot be determined until the
transactions occur.
SFAS
160
In
December 2007, the FASB issued SFAS 160, Noncontrolling Interests in
Consolidated Financial Statements-an Amendment of ARB No. 51 (SFAS
160). SFAS 160 establishes accounting and reporting standards that
require that the ownership percentages in subsidiaries held by parties other
than the parent be clearly identified, labeled, and presented separately from
the parent’s equity in the equity section of the consolidated balance sheet; the
amount of consolidated net income attributable to the parent and the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement; that changes in the parent’s ownership
interest while it retains control over its subsidiary be accounted for
consistently; that when a subsidiary is deconsolidated, any retained
noncontrolling equity investment be initially measured at fair value; and that
sufficient disclosure is made to clearly identify and distinguish between the
interests of the parent and the noncontrolling owners. SFAS 160
applies to all entities that prepare consolidated financial statements, except
for non-profit entities. SFAS 160 is effective for fiscal years
beginning after December 31, 2008. Early adoption is not
permitted. The Company will adopt SFAS 160 on January 1, 2009, and is
currently assessing the impact this statement will have on its financial
statements and results of operations.
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 nonutility plant, valuing reclamation
liabilities, valuing derivative contracts, and estimating uncollectible accounts
and coal reserves, 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 both a qualitative and quantitative review
of that investment and when necessary 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 2007,
the Company examined the recoverability of several investments, including a
leveraged lease and a note receivable. The Company determined the
carrying values of the investments tested were not impaired. For the
lease, this assessment was based on a recent nonbinding offer from an unrelated
party to purchase the underlying property. However, a sale price 10
percent below that received would have resulted in a small charge to
earnings. For the note, a qualitative assessment was made regarding
collection using the note agreement’s breach of contract
provisions. Based on that review, the Company believes collection is
probable.
In 2006,
the Company fully impaired its investment in Pace Carbon. The Company
took this action because of the effect high oil prices had on Pace Carbon’s
future operations. The write off of the investment and expensing of
future funding requirements totaled $9.5 million, or $5.7 million after tax in
2006.
Goodwill and Intangible
Assets
Pursuant
to SFAS 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 2007, 2006, and 2005 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.
The
Company also annually tests non-amortizing intangible assets for impairment and
amortizing intangible assets are tested on an event and circumstance
basis. During 2007, 2006, and 2005, these tests yielded no impairment
charges.
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 currently measures its obligations annually on
September 30. However, the Company is in the process of moving is
measurement date to December 31. The Company used the following
weighted average assumptions to develop 2007 periodic benefit cost: a
discount rate of 5.85 percent percent, an expected return on plan assets of 8.25
percent percent, a rate of compensation increase of 3.75 percent percent, and an
inflation assumption of 3.5 percent percent. During 2007, the Company
increased the discount rate by 40 basis points to value 2007 ending pension and
postretirement obligations and 2008 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 generally
increase periodic benefit cost by approximately $1 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 and
liabilities. 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, 2007, totaled $183 million
and $171 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, 2007, totaled
$700 million and $386 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.
Financing Cash Flow
The
Company’s common stock dividends are primarily funded by utility
operations. Nonutility operations have demonstrated 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 of the senior unsecured debt of Utility Holdings and Indiana Gas,
at December 31, 2007, are A-/Baa1 as rated by Standard and Poor's Ratings
Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s),
respectively. The credit ratings on SIGECO's 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 percent 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
50 percent and 48 percent of long-term capitalization at December 31, 2007, and
December 31, 2006, 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 the majority 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 may
require additional permanent financing. The Company expects to settle
an equity forward contract and plans to issue long-term debt within the next
twelve months as more fully described below. As of December 31, 2007,
the Company was in compliance with all financial covenants.
Sources & Uses of
Liquidity
Operating Cash
Flow
The
Company's primary source of liquidity to fund working capital requirements has
been cash generated from operations, which totaled $298.1 million in 2007,
compared to $310.2 million in 2006 and $268.4 million in 2005.
While net
income increased substantially in 2007 compared to 2006, cash flow from
operating activities decreased $12.1 million. The decrease was
primarily a result of changes in working capital accounts and lower
distributions from equity method investments compared to the prior
year. Net income before non-cash charges of $363.2 million increased
$60.3 million, compared to $302.9 million in 2006. Working capital
changes used cash of $27.0 million in 2007 compared to cash generated of $16.6
million in 2006. Distributions from equity method investments, which
principally consist of dividends from ProLiance, were $20.8 million in 2007
compared to $35.8 million in 2006. Distributions in 2006 include a
$10.4 million special dividend from ProLiance. The remaining decrease
is primarily attributable to increased contributions to pension
plans.
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 and
the special ProLiance dividend. Earnings before non-cash charges were
impacted by $15.5 million in alternative minimum taxes in 2005.
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 recently executed
long-term financing, increases in common stock dividends over the periods
presented, and changes in short term borrowings. In 2007 financing
activities were generally flat, with short-term and long-term debt proceeds and
stock option proceeds offsetting debt payments and dividends. 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.
SIGECO Pollution Control
Bonds
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt has a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate will be reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac.
Utility Holdings2006 Debt
Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95 percent 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 percent 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 percent Senior Notes originally due October 15, 2031. These
notes were redeemed on October 19, 2006 at par plus accrued
interest.
Utility Holdings2005 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
percent priced at 99.799 percent to yield 5.47 percent to maturity (2015
Notes). The second tranche was 30-year notes due December 2035 with
an interest rate of 6.10 percent priced at 99.779 percent to yield 6.11 percent
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 percent 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 percent Guaranteed Senior Notes, Series
A due 2010, (ii) $25 million 5.13 percent Guaranteed Senior Notes, Series B due
2012 and (iii) $75 million 5.31 percent 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 percent.
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 percent Senior Notes due 2005, (ii)
$17.5 million 7.83 percent Senior Notes due 2007, (iii) $22.5 million 7.98
percent 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 percent 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) replace a more limited support
agreement with an unconditional guarantee by Vectren and (iv) provide for a 100
basis point increase in interest rates if the ratio of consolidated total debt
to total capitalization exceeds 65 percent.
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 2007, 2006 and
2005, no debt 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 and Indiana Gas
Debt Calls
In 2006,
the Company called at par approximately $100 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 senior unsecured notes originally
due in 2030. The notes called in 2006 and 2005 had stated interest
rates of 7.25 percent and 7.45 percent, 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 percent to 5.00 percent. After the
remarketing, interest rates are reset every seven days using an auction
process.
As part
of the integration of Miller into the Company’s consolidated financing model,
$24 million of Miller’s outstanding long-term debt was retired in the fourth
quarter of 2006.
Other
debt approximating $24 million in 2007 and $38 million in 2005 was retired as
scheduled.
Investing Cash
Flow
Cash flow
required for investing activities was $303.0 million in 2007, $337.4 million in
2006, and $239.6 million in 2005. Capital expenditures are the
primary component of investing activities and totaled $334.5 million in 2007,
compared to $281.4 million in 2006 and $231.6 million in 2005. The
years ended December 31, 2007 and 2006 include higher levels of expenditures for
environmental compliance equipment, and 2007 was also impacted by increased
spending for electric transmission, a new gas line serving a Honda plant under
construction in the Vectren North service territory, and coal mine
development.
Other
investments in 2006 were principally impacted by the acquisition of Miller and
advance coal mine royalty payments. Investing cash flow in 2007
includes the receipt of $44.9 million in proceeds from the sale of
SIGECOM.
Available Sources of
Liquidity
Short-term Borrowing
Arrangements
At
December 31, 2007, the Company has $780 million of short-term borrowing
capacity, including $520 million for the Utility Group and $260 million for the
wholly owned Nonutility Group and corporate operations, of which approximately
$134 million is available for the Utility Group operations and approximately $89
million is available for the wholly owned Nonutility Group and corporate
operations.
Common Stock
Offering
In
February 2007, the Company sold 4.6 million authorized but previously unissued
shares of its common stock to a group of underwriters in an SEC-registered
primary offering at a price of $28.33 per share. The transaction
generated proceeds, net of underwriting discounts and commissions, of
approximately $125.7 million. The Company executed an equity forward
sale agreement (equity forward) in connection with the offering, and therefore,
did not receive proceeds at the time of the equity offering. The
equity forward allows the Company to price an offering under market conditions
existing at that time, and to better match the receipt of the offering proceeds
and the associated share dilution with the implementation of regulatory
initiatives, providing a return on the new equity employed. The
offering proceeds, when and if received, will be used to permanently finance
primarily electric utility capital expenditures.
In
connection with the equity forward, an affiliate of one of the underwriters (the
forward seller), at the Company's request, borrowed an equal number of shares of
the Company's common stock from institutional stock lenders and sold those
borrowed shares to the public in the primary offering. The Company
will receive an amount equal to the net proceeds from that sale, subject to
certain adjustments defined in the equity forward, upon full share settlement of
the equity forward. Those adjustments defined in the equity forward
include 1) daily increases in the forward sale price based on a floating
interest factor equal to the federal funds rate, less a 35 basis point
fixed spread, and 2) structured quarterly decreases to the forward sale price
that align with expected Company dividend payments.
The
Company may elect to settle the equity forward in shares or in cash, except in
specified circumstances or events where the counterparty to the equity forward
could force a share settlement. Examples of such events include, but
are not limited to, the Company making dividend payments greater than the
structured quarterly decreases identified in the equity forward or the Company
repurchasing a number of its outstanding common shares over a specified
threshold. If the Company elects to settle in shares, the maximum
number of shares deliverable by the Company is 4.6 million shares. If
the Company elects to settle in cash, an affiliate of one of the underwriters
(the forward purchaser) would purchase shares in the market and return those
shares to the stock lenders. The Company will either owe or be owed
funds depending upon the Company's average share price during the "unwind
period" defined in the equity forward in relation to the equity forward's
contracted price. Generally, if the equity forward's contracted price
is lower than the average share price during the "unwind period", then the
Company would owe cash; and if the average share price during the "unwind
period" is less than the equity forward's contracted price, the Company would
receive cash. Proceeds received or paid when the equity forward is
settled will be recorded in Common Shareholders' Equity,
even if settled in cash. The equity forward must be settled prior to
February 28, 2009.
The
equity forward had an initial forward price of $27.34 per share, representing
the public offering price of $28.33 per share, net of underwriting discounts and
commissions. Management therefore estimated the contract had no
initial fair value. If the equity forward had been settled by
delivery of shares at December 31, 2007, the Company would have received
approximately $126.4 million based on a forward price of $27.47 for the 4.6
million shares. If the Company had elected to settle the equity
forward in cash at December 31, 2007, the Company estimates it would have paid
approximately $3 million, assuming the price in the “unwind period” approximates
the trailing three month average of Vectren’s stock price. The
federal funds rate was 4.50 percent at December 31, 2007. The
Company currently anticipates settling the equity forward by delivering
shares.
New Share
Issues
The
Company may periodically issue new common shares to satisfy the dividend
reinvestment plan, stock option plan and other employee benefit plan
requirements. New issuances added additional liquidity of $5.2
million in 2007.
Utility Holdings Debt Shelf
Registration
Utility
Holdings filed a shelf registration statement with the Securities and Exchange
Commission for $300 million aggregate principal amount of unsecured senior notes
in September 2007, which is anticipated to meet Utility Holdings’ estimated debt
financing requirements over the next 3 years. In October 2007 the SEC
declared the registration statement to be effective. When issued, the
unsecured notes will be guaranteed by Utility Holdings’ three operating utility
companies: SIGECO, Indiana Gas, and VEDO. These guarantees of
Utility Holdings’ debt will be full and unconditional and joint and
several. In contemplation of a 2008 issuance, the Company executed
forward starting interest rate swaps with a total notional amount of $80 million
that expire in 2008.
Known & 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 $10 and $8 million in 2008 and 2009. During 2007,
approximately $17 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 2008 - 2012 are estimated as follows:
|
(In
millions)
|
2008
|
2009
|
2010
|
2011
|
2012
|
|||||||||||||||
|
Utility
Group
|
$ |
312.7
|
$ |
282.2
|
$ |
295.9
|
$ |
228.8
|
$ |
207.7
|
||||||||||
|
Nonutility
Group
|
122.2
|
55.0
|
36.3
|
34.7
|
35.2
|
|||||||||||||||
|
Total
capital expenditures & investments
|
$ |
434.9
|
$ |
337.2
|
$ |
332.2
|
$ |
263.5
|
$ |
242.9
|
||||||||||
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2007:
|
(In
millions)
|
Total
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
|||||||||||||||||||||
|
Long-term
debt (1)
|
$ |
1,248.7
|
$ |
-
|
$ |
-
|
$ |
47.5
|
$ |
250.0
|
$ |
60.0
|
$ |
891.2
|
||||||||||||||
|
Short-term
debt
|
557.0
|
557.0
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||||||||
|
Long-term
debt interest commitments
|
406.5
|
75.1
|
75.1
|
75.0
|
70.7
|
53.7
|
56.9
|
|||||||||||||||||||||
|
Firm
commodity purchase commitments
|
75.7
|
59.9
|
7.1
|
2.9
|
2.9
|
2.9
|
-
|
|||||||||||||||||||||
|
Plant
purchase commitments (2)
|
40.6
|
36.6
|
4.0
|
-
|
-
|
-
|
-
|
|||||||||||||||||||||
|
Operating
leases
|
15.1
|
5.6
|
4.0
|
3.0
|
1.2
|
0.6
|
0.7
|
|||||||||||||||||||||
|
Total
(3)
|
$ |
2,343.6
|
$ |
734.2
|
$ |
90.2
|
$ |
128.4
|
$ |
324.8
|
$ |
117.2
|
$ |
948.8
|
||||||||||||||
|
(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 2007 (in millions) is zero in
2008, $80.0 in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012
and thereafter.
|
|
(2)
|
The
settlement period of these utility & nonutility plant obligations is
estimated.
|
|
(3)
|
The
Company has $6.2 million in unrecognized tax benefits for which the
expected settlement date cannot be
estimated.
|
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase natural gas and electricity 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.
In
February 2008, SIGECO began the process of providing notice to the current
holders of approximately $103 million of tax exempt auction rate mode long term
debt that the Company will convert that debt from its current auction rate mode
into a daily interest rate mode during March 2008. The debt will be
subject to mandatory tender for purchase on the conversion date at 100 percent
of the principal amount plus accrued interest.
Off Balance Sheet
Arrangements
Other Guarantees and Letters of
Credit
In the
normal course of business, 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, 2007, guarantees issued and outstanding on behalf of
unconsolidated affiliates approximated $3 million. The Company has
accrued no liabilities for these guarantees as they relate to guarantees issued
among related parties.
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, 2007, Vectren Corporation has a liability
representing the fair value of that guarantee of less than $0.1
million. Liabilities accrued for, and activity related to, product
warranties are not significant. Through December 31, 2007, 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 transportation
and storage 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 industry, including the 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, fines, penalties and
other effects of legal and administrative proceedings, settlements,
investigations, claims, including, but not limited to, such matters
involving compliance with state and federal laws and interpretations of
these laws.
|
|
·
|
Changes in federal, state or
local legislative requirements, such as changes in tax laws or rates,
environmental laws, including laws governing greenhouse gases, mandates of
sources of renewable energy, and other
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 may also
execute 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
transactions involving purchases and sales of natural gas and electricity for
the benefit of 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. Constructive regulatory orders, such as that authorizing
lost margin recovery and recovery of unaccounted for gas and other gas related
expenses, also mitigate the effect volatile gas costs may have on the Company’s
financial condition.
Although
Vectren’s regulated operations are exposed to limited commodity price risk,
volatile natural gas prices have other effects such as higher working capital
requirements, higher interest costs, and some level of price-sensitivity in
volumes sold or delivered. The Company will manage these risks by
executing derivative contracts that hedge 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. Therefore, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
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. No market sensitive derivative positions were outstanding
on December 31, 2007 and 2006.
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, 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 sells commodities, including electricity, natural gas, and
coal to meet customer demands and operational needs. The Company
executes forward contracts and occasionally 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 an annual average
of 20 percent and 30 percent of its total debt to be exposed to variable rate
volatility. However, this targeted range may be exceeded during the
seasonal increases in short-term borrowing. To manage this exposure,
the Company may use derivative financial instruments.
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 2007 and 2006, the weighted average
combined borrowings under these arrangements approximated $495 million and $342
million, respectively. At December 31, 2007 and 2006, combined
borrowings under these arrangements were $660.1 million and $550.9 million,
respectively. Based upon average borrowing rates under these
facilities during the years ended December 31, 2007 and 2006, an increase of 100
basis points (one percentage point) in the rates would have increased interest
expense by $4.9 million and $3.4 million, respectively.
At
December 31, 2007, SIGECO has approximately $103 million of tax-exempt
adjustable rate long-term debt where the interest rates on this debt are reset
every seven days through an auction process. Throughout 2007, the weighted
average interest rate associated with this debt was 4.15 percent. If these
auctions were to fail, interest rates would reset to the maximum rates permitted
under the various debt indentures of 10 percent to 15 percent for the following
week. On a weekly basis, interest expense using these maximum rates would
be approximately $200,000 higher than the average weekly interest expense based
on rates experienced during 2007. No SIGECO auctions failed during 2007
nor have they during the period since Vectren was formed in 2000.
However, in February 2008, significant
disruptions occurred in the overall auction rate debt markets. As a result, many
auctions of tax exempt debt, including some of those involving SIGECO's auction
rate debt, failed as a result of insufficient order interest from potential
investors. These failures are largely attributable to a lack of liquidity in the
market place arising from downgrades in, and negative watches regarding, credit
ratings of monoline insurers that guarantee the timely repayment of bond
principal and interest if an issuer defaults as well as from disruptions in the
overall financial markets. Monoline insurer Ambac Assurance Corporation insures
the Company's auction rate long-term debt. As a result of these failed auctions,
the Company has experienced, and may continue to experience, increased interest
costs.
Subject
to applicable notice provisions, SIGECO may, at its option, redeem this auction
rate debt at par value plus the accrued and unpaid interest or elect to utilize
other interest rate modes available to it as defined in the various debt
indentures. SIGECO is in the process of providing notice to current holders of
this debt that it will be converted from the auction rate mode into a daily
interest rate mode during March 2008 and the debt will be subject to mandatory
tender for purchase on the conversion date at 100 percent of the principal
amount plus accrued interest. Following
conversion to the daily mode, SIGECO maintains its options to again convert the
debt to other interest rate modes and remarket it to investors or redeem the
debt and reissue new debt, including the possibility of replacing it with
taxable debt from Utility Holdings.
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. In addition, credit risk is mitigated by
regulatory orders that allow recovery of all bad debt expense in Ohio and the
gas cost portion of bad debt expense in Indiana.
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,
2007. Management certified this fact in its Sarbanes Oxley Section
302 certifications, which are attached as exhibits to this 2007 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, 2007 and 2006, 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,
2007. Our audits also included the financial statement schedule
included in the Index at Item 15. These financial statements and
financial statement schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule 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. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of Vectren Corporation and subsidiaries as of
December 31, 2007 and 2006, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2007, 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.
As
discussed in Note 7 to the consolidated financial statements, in 2006 the
Company adopted the provisions of Statement of Financial Accounting Standards
No. 158, Employers’ Accounting
for Defined Benefit Pension and Other Postretirement Plans — an amendment of
FASB Statements No. 87, 88, 106 and 132(R).
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial
reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 19, 2008 expressed an
unqualified opinion on the Company’s internal control over financial
reporting.
DELOITTE
& TOUCHE LLP
Indianapolis,
Indiana
February
19, 2008
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of Vectren Corporation:
We have
audited the internal control over financial reporting of Vectren Corporation and
subsidiaries (the “Company”) as of December 31, 2007, 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 maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting included in the accompanying Management’s Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting based on our
audit.
We
conducted our audit 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
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe that our
audit provides 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 Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2007, based on the criteria
established in Internal
Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31, 2007 of
the Company and our report dated February 19, 2008 expressed an unqualified
opinion on those financial statements and financial statement schedule and
included an explanatory paragraph regarding their 2006 change in method of
accounting for defined benefit pension and other postretirement
plans.
DELOITTE
& TOUCHE LLP
Indianapolis,
Indiana
February
19, 2008
VECTREN CORPORATION AND SUBSIDIARY
COMPANIES
|
|
CONSOLIDATED BALANCE
SHEETS
|
(In
millions)
|
At December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
& cash equivalents
|
$ |
20.6
|
$ |
32.8
|
||||
|
Accounts
receivable - less reserves of $3.7 &
|
||||||||
|
$3.3,
respectively
|
189.4
|
198.6
|
||||||
|
Accrued
unbilled revenues
|
168.2
|
146.5
|
||||||
|
Inventories
|
160.9
|
163.5
|
||||||
|
Recoverable
fuel & natural gas costs
|
-
|
1.8
|
||||||
|
Prepayments
& other current assets
|
160.5
|
172.7
|
||||||
|
Total current
assets
|
699.6
|
715.9
|
||||||
|
Utility
Plant
|
||||||||
|
Original
cost
|
4,062.9
|
3,820.2
|
||||||
|
Less: accumulated
depreciation & amortization
|
1,523.2
|
1,434.7
|
||||||
|
Net utility
plant
|
2,539.7
|
2,385.5
|
||||||
|
Investments
in unconsolidated affiliates
|
208.8
|
181.0
|
||||||
|
Other
investments
|
77.0
|
74.5
|
||||||
|
Nonutility
property - net
|
320.3
|
294.4
|
||||||
|
Goodwill
- net
|
238.0
|
237.8
|
||||||
|
Regulatory
assets
|
175.3
|
163.5
|
||||||
|
Other
assets
|
37.7
|
39.0
|
||||||
|
TOTAL
ASSETS
|
$ |
4,296.4
|
$ |
4,091.6
|
||||
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,
|
||||||||
|
2007
|
2006
|
|||||||
|
LIABILITIES &
SHAREHOLDERS' EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable
|
$ |
187.4
|
$ |
180.0
|
||||
|
Accounts
payable to affiliated companies
|
83.7
|
89.9
|
||||||
|
Refundable
fuel & natural gas costs
|
27.2
|
35.3
|
||||||
|
Accrued
liabilities
|
171.8
|
147.2
|
||||||
|
Short-term
borrowings
|
557.0
|
464.8
|
||||||
|
Current
maturities of long-term debt
|
0.3
|
24.2
|
||||||
|
Long-term
debt subject to tender
|
-
|
20.0
|
||||||
|
Total current
liabilities
|
1,027.4
|
961.4
|
||||||
|
Long-term
Debt - Net of Current Maturities &
|
||||||||
|
Debt
Subject to Tender
|
1,245.4
|
1,208.0
|
||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||
|
Deferred
income taxes
|
318.1
|
260.7
|
||||||
|
Regulatory
liabilities
|
307.2
|
291.1
|
||||||
|
Deferred
credits & other liabilities
|
164.2
|
195.8
|
||||||
|
Total deferred credits &
other liabilities
|
789.5
|
747.6
|
||||||
|
Minority
Interest in Subsidiary
|
0.4
|
0.4
|
||||||
|
Commitments
& Contingencies (Notes 3, 12-14)
|
||||||||
|
Common
Shareholders' Equity
|
||||||||
| Common stock (no par value) – issued & outstanding 76.3 and 76.1, respectively | 532.7 | 525.5 | ||||||
|
Retained
earnings
|
688.5
|
643.6
|
||||||
|
Accumulated
other comprehensive income
|
12.5
|
5.1
|
||||||
|
Total common shareholders'
equity
|
1,233.7
|
1,174.2
|
||||||
|
TOTAL LIABILITIES &
SHAREHOLDERS' EQUITY
|
$ |
4,296.4
|
$ |
4,091.6
|
||||
|
|
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ |
1,269.4
|
$ |
1,232.5
|
$ |
1,359.7
|
||||||
|
Electric
utility
|
487.9
|
422.2
|
421.4
|
|||||||||
|
Nonutility
revenues
|
524.6
|
386.9
|
246.9
|
|||||||||
|
Total operating
revenues
|
2,281.9
|
2,041.6
|
2,028.0
|
|||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
847.2
|
841.5
|
973.3
|
|||||||||
|
Cost
of fuel & purchased power
|
174.8
|
151.5
|
144.1
|
|||||||||
|
Cost
of nonutility revenues
|
287.7
|
248.7
|
191.0
|
|||||||||
|
Other
operating
|
456.9
|
341.8
|
282.2
|
|||||||||
|
Depreciation
& amortization
|
184.8
|
172.3
|
158.2
|
|||||||||
|
Taxes
other than income taxes
|
70.0
|
65.3
|
66.1
|
|||||||||
|
Total
operating expenses
|
2,021.4
|
1,821.1
|
1,814.9
|
|||||||||
|
OPERATING
INCOME
|
260.5
|
220.5
|
213.1
|
|||||||||
|
OTHER
INCOME
|
||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
22.9
|
17.0
|
45.6
|
|||||||||
|
Other
– net
|
36.8
|
(2.7 | ) |
6.2
|
||||||||
|
Total
other income
|
59.7
|
14.3
|
51.8
|
|||||||||
|
Interest
expense
|
101.0
|
95.6
|
83.9
|
|||||||||
|
INCOME BEFORE INCOME
TAXES
|
219.2
|
139.2
|
181.0
|
|||||||||
|
Income
taxes
|
76.0
|
30.3
|
44.1
|
|||||||||
|
Minority
interest
|
0.1
|
0.1
|
0.1
|
|||||||||
|
NET
INCOME
|
$ |
143.1
|
$ |
108.8
|
$ |
136.8
|
||||||
|
AVERAGE
COMMON SHARES OUTSTANDING
|
75.9
|
75.7
|
75.6
|
|||||||||
|
DILUTED
COMMON SHARES OUTSTANDING
|
76.6
|
76.2
|
76.1
|
|||||||||
|
EARNINGS
PER SHARE OF COMMON STOCK:
|
||||||||||||
|
BASIC
|
$ |
1.89
|
$ |
1.44
|
$ |
1.81
|
||||||
|
DILUTED
|
$ |
1.87
|
$ |
1.43
|
$ |
1.80
|
||||||
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net
income
|
$ |
143.1
|
$ |
108.8
|
$ |
136.8
|
||||||
|
Adjustments to reconcile net income to cash from operating
activities:
|
||||||||||||
|
Depreciation
& amortization
|
184.8
|
172.3
|
158.2
|
|||||||||
|
Deferred income taxes & investment tax credits
|
27.0
|
1.4
|
(8.6 | ) | ||||||||
|
Equity in earnings of unconsolidated affiliates
|
(22.9 | ) | (17.0 | ) | (45.6 | ) | ||||||
|
Provision for uncollectible accounts
|
16.6
|
15.3
|
15.1
|
|||||||||
|
Expense portion of pension & postretirement benefit
cost
|
9.8
|
10.7
|
10.7
|
|||||||||
|
Other non-cash charges - net
|
4.8
|
11.4
|
1.9
|
|||||||||
|
Changes in working capital accounts:
|
||||||||||||
|
Accounts
receivable & accrued unbilled revenue
|
(29.1 | ) |
108.9
|
(102.9 | ) | |||||||
|
Inventories
|
2.6
|
(17.6 | ) | (71.9 | ) | |||||||
|
Recoverable/refundable
fuel & natural gas costs
|
(6.3 | ) |
41.3
|
3.5
|
||||||||
|
Prepayments
& other current assets
|
(3.7 | ) | (21.2 | ) |
36.1
|
|||||||
|
Accounts
payable, including to affiliated companies
|
4.9
|
(71.6 | ) |
101.2
|
||||||||
|
Accrued
liabilities
|
4.6
|
(23.2 | ) |
27.4
|
||||||||
|
Unconsolidated affiliate
dividends
|
20.8
|
35.8
|
18.8
|
|||||||||
|
Changes
in noncurrent assets
|
(21.4 | ) | (25.8 | ) | (6.9 | ) | ||||||
|
Changes
in noncurrent liabilities
|
(37.5 | ) | (19.3 | ) | (5.4 | ) | ||||||
|
Net cash flows from operating
activities
|
298.1
|
310.2
|
268.4
|
|||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds from:
|
||||||||||||
|
Long-term debt
- net of issuance costs
|
16.4
|
92.8
|
274.2
|
|||||||||
|
Stock
option exercises & other stock plans
|
5.2
|
-
|
-
|
|||||||||
|
Requirements for:
|
||||||||||||
|
Dividends on
common stock
|
(96.4 | ) | (93.1 | ) | (90.5 | ) | ||||||
|
Retirement of
long-term debt
|
(23.9 | ) | (124.4 | ) | (88.5 | ) | ||||||
|
Redemption of
preferred stock of subsidiary
|
-
|
-
|
(0.1 | ) | ||||||||
|
Net change in short-term borrowings
|
92.2
|
164.9
|
(112.5 | ) | ||||||||
|
Other
activity
|
(0.8 | ) | (0.6 | ) | (0.6 | ) | ||||||
|
Net cash flows from financing
activities
|
(7.3 | ) |
39.6
|
(18.0 | ) | |||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Unconsolidated
affiliate distributions
|
12.7
|
2.0
|
6.9
|
|||||||||
|
Other
collections
|
38.0
|
3.4
|
4.3
|
|||||||||
|
Requirements
for:
|
||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(334.5 | ) | (281.4 | ) | (231.6 | ) | ||||||
|
Unconsolidated
affiliate investments
|
(17.5 | ) | (16.7 | ) | (19.2 | ) | ||||||
|
Other
investments
|
(1.7 | ) | (44.7 | ) |
-
|
|||||||
|
Net cash flows from investing
activities
|
(303.0 | ) | (337.4 | ) | (239.6 | ) | ||||||
|
Net
change in cash & cash equivalents
|
(12.2 | ) |
12.4
|
10.8
|
||||||||
|
Cash
& cash equivalents at beginning of period
|
32.8
|
20.4
|
9.6
|
|||||||||
|
Cash
& cash equivalents at end of period
|
$ |
20.6
|
$ |
32.8
|
$ |
20.4
|
||||||
|
Cash
paid during the year for:
|
||||||||||||
|
Interest
|
$ |
97.3
|
$ |
92.9
|
$ |
79.6
|
||||||
|
Income
taxes
|
43.7
|
36.3
|
48.1
|
|||||||||
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, 2005
|
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 million in tax
|
0.2
|
0.2
|
||||||||||||||||||
|
Cash
flow hedges
|
||||||||||||||||||||
|
unrealized
gains(losses) - net of $2.9 million in tax
|
4.2
|
4.2
|
||||||||||||||||||
|
reclassifications
to net income- net of $0.2 million in tax
|
(0.2 | ) | (0.2 | ) | ||||||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||||||
|
affiliates
- net of $1.8 million in tax
|
(2.8 | ) | (2.8 | ) | ||||||||||||||||
|
Total
comprehensive income
|
138.2
|
|||||||||||||||||||
|
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 million in tax
|
7.9
|
7.9
|
||||||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||||||
|
unrealized
gains(losses) - net of $1.7 million in tax
|
(2.6 | ) | (2.6 | ) | ||||||||||||||||
|
reclassifications
to net income- net of $0.7 million in tax
|
(1.0 | ) | (1.0 | ) | ||||||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||||||
|
affiliates
- net of $4.3 million in tax
|
6.4
|
6.4
|
||||||||||||||||||
|
Total
comprehensive income
|
119.5
|
|||||||||||||||||||
|
Adoption
of SFAS 158 - net of $5.2 million 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
|
|||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net
income
|
143.1
|
143.1
|
||||||||||||||||||
|
SFAS
158 funded status adjustment - net of $0.5 million in tax
|
0.7
|
0.7
|
||||||||||||||||||
|
Cash
flow hedges
|
||||||||||||||||||||
|
unrealized
gains(losses) - net of $0.3 million in tax
|
0.9
|
0.9
|
||||||||||||||||||
|
reclassifications
to net income- net of $0.3 million in tax
|
(1.0 | ) | (1.0 | ) | ||||||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||||||
|
affiliates
- net of $4.2 in tax
|
6.8
|
6.8
|
||||||||||||||||||
|
Total
comprehensive income
|
150.5
|
|||||||||||||||||||
|
Adoption
of FIN 48
|
(0.1 | ) | (0.1 | ) | ||||||||||||||||
|
Common
stock:
|
||||||||||||||||||||
|
Stock
option exercises & other stock plans
|
0.2
|
5.2
|
5.2
|
|||||||||||||||||
|
Dividends
($1.27 per share)
|
(96.4 | ) | (96.4 | ) | ||||||||||||||||
|
Other
|
2.0
|
(1.8 | ) |
0.2
|
||||||||||||||||
|
Balance at December 31,
2007
|
76.3
|
$ |
532.7
|
$ |
688.5
|
$ |
12.5
|
$ |
1,233.7
|
|||||||||||
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 or Vectren North),
Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the
Ohio operations (VEDO or Vectren Ohio). 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
are holding companies as defined by the Energy Policy Act of 2005 (Energy
Act). Vectren was incorporated under the laws of Indiana on June 10,
1999.
Indiana
Gas provides energy delivery services to over 568,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 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 percent ownership), and Indiana Gas (47
percent ownership). The Ohio operations generally do business as
Vectren Energy Delivery of Ohio.
The
Company, through Vectren Enterprises, Inc. (Enterprises), is 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 services and performance contracting and renewable
energy 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 in the past
invested in projects that generated 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. These entities are involved in activities surrounding
multifamily housing and office properties. The Company’s exposure to
loss is limited to its investment which as of December 31, 2007, and 2006,
totaled $11.4 million and $13.4 million, respectively, recorded in Investments in unconsolidated
affiliates, and $11.5 million in both years recorded in Other
investments. The Company is also the equity owner in three
leveraged leases, which as of December 31, 2007, and 2006, totaled $11.0 million
and $10.2 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)
|
2007
|
2006
|
||||||
|
Gas
in storage – at average cost
|
$ |
76.8
|
$ |
73.0
|
||||
|
Materials
& supplies
|
33.0
|
29.5
|
||||||
|
Fuel
(coal & oil) for electric generation
|
30.6
|
31.2
|
||||||
|
Gas
in storage – at LIFO cost
|
16.7
|
26.5
|
||||||
|
Other
|
3.8
|
3.3
|
||||||
|
Total
inventories
|
$ |
160.9
|
$ |
163.5
|
||||
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, 2007, and 2006, by approximately $73.0 million and $79.0 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)
|
2007
|
2006
|
||||||||||||||
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|||||||||||||
|
Gas
utility plant
|
$ |
2,077.5
|
3.6%
|
$ |
1,956.1
|
3.6%
|
||||||||||
|
Electric
utility plant
|
1,815.8
|
3.3%
|
1,685.5
|
3.4%
|
||||||||||||
|
Common
utility plant
|
45.5
|
2.8%
|
45.2
|
3.0%
|
||||||||||||
|
Construction
work in progress
|
124.1
|
-
|
133.4
|
-
|
||||||||||||
|
Total original
cost
|
$ |
4,062.9
|
$ |
3,820.2
|
||||||||||||
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)
|
2007
|
2006
|
2005
|
|||||||||
|
AFUDC
– borrowed funds
|
$ |
3.5
|
$ |
2.6
|
$ |
1.6
|
||||||
|
AFUDC
– equity funds
|
0.5
|
1.5
|
0.3
|
|||||||||
|
Total
AFUDC
|
$ |
4.0
|
$ |
4.1
|
$ |
1.9
|
||||||
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, 2007 is $63.5 million with
accumulated depreciation totaling $46.6 million. The construction
work-in-progress balance associated with SIGECO’s ownership interest totaled
$56.4 million at December 31, 2007. 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)
|
2007
|
2006
|
||||||
|
Computer
hardware & software
|
$ |
117.0
|
$ |
107.7
|
||||
|
Land
& buildings
|
76.2
|
73.4
|
||||||
|
Coal
mine development costs & equipment
|
71.3
|
59.7
|
||||||
|
Vehicles
& equipment
|
35.0
|
33.0
|
||||||
|
All
other
|
20.8
|
20.6
|
||||||
|
Nonutility property -
net
|
$ |
320.3
|
$ |
294.4
|
||||
The
depreciation of nonutility property is charged against income over its estimated
useful life (ranging from 3.5 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 $258.7 million and $217.0
million as of December 31, 2007, and 2006, respectively. For the
years ended December 31, 2007, 2006, and 2005, the Company capitalized interest
totaling $2.3 million, $1.2 million, and $0.4 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, 2007, 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 $33.0 million is attributable to the
Nonutility Group.
|
G.
|
Intangible
Assets
|
Intangible
assets consist of the following:
|
(In
millions)
|
At
December 31,
|
|||||||||||||||
|
2007
|
2006
|
|||||||||||||||
|
Amortizing
|
|
Non-amortizing
|
Amortizing
|
Non-amortizing
|
||||||||||||
|
Customer-related
assets
|
$ |
8.9
|
$ |
-
|
$ |
9.6
|
$ |
-
|
||||||||
|
Market-related
assets
|
0.1
|
7.0
|
0.1
|
7.0
|
||||||||||||
|
Intangible assets,
net
|
$ |
9.0
|
$ |
7.0
|
$ |
9.7
|
$ |
7.0
|
||||||||
For
amortizing intangible assets, the weighted average remaining life for
customer-related assets is 24.3 years and for market-related assets is 2.5
years. The total weighted average life is 23.8
years. These amortizing intangible assets have no significant
residual values. Intangible assets are presented net of accumulated
amortization totaling $2.0 million for customer-related assets and $0.2 million
for market-related assets at December 31, 2007 and $0.2 million for
customer-related assets and $0.2 million for market-related assets at December
31, 2006. In 2007, 2006 and 2005, amortization associated with
intangible assets was $0.7 million, $0.5 million and $0.5 million, respectively,
and should approximate that amount in each of the next five
years. Intangible assets are primarily in the Nonutility
Group.
The
Company also has emission allowances relating to its wholesale power marketing
operations totaling $2.6 million and $4.2 million at December 31, 2007 and 2006,
respectively. The value of the emission allowances are recognized as
they are consumed or sold on the open market.
|
H.
|
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).
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)
|
2007
|
2006
|
||||||
|
Future
amounts recoverable from ratepayers related to:
|
||||||||
|
Benefit
obligations
|
$ |
23.6
|
$ |
46.7
|
||||
|
Income
taxes
|
14.0
|
13.3
|
||||||
|
Interest
rate derivatives
|
8.9
|
-
|
||||||
|
Asset
retirement obligations & other
|
10.9
|
1.9
|
||||||
|
57.4
|
61.9
|
|||||||
|
Amounts
deferred for future recovery chared to customers related
to:
|
||||||||
|
Demand
side management programs
|
-
|
27.7
|
||||||
|
MISO-related
costs
|
-
|
17.1
|
||||||
|
Cost
recovery riders & other
|
1.9
|
4.7
|
||||||
|
1.9
|
49.5
|
|||||||
|
Amounts
currently recovered in customer rates related
to:
|
||||||||
|
Demand
side management programs
|
27.6
|
1.5
|
||||||
|
Unamortized
debt issue costs & hedging proceeds
|
25.0
|
26.4
|
||||||
|
Indiana
authorized trackers
|
21.5
|
6.1
|
||||||
|
MISO-related
costs
|
20.8
|
-
|
||||||
|
Ohio
authorized trackers
|
10.4
|
10.4
|
||||||
|
Premiums
paid to reacquire debt & other
|
10.7
|
7.7
|
||||||
|
116.0
|
52.1
|
|||||||
|
Total
regulatory assets
|
$ |
175.3
|
$ |
163.5
|
||||
Of the
$116.0 million currently being recovered in customer rates charged to customers,
$27.6 million is earning a return. The weighted average recovery
period of regulatory assets currently being recovered is 8 years. The
Company has rate orders for all deferred costs not yet in rates and therefore
believes that future recovery is probable.
-60-
Regulatory
Liabilities
At
December 31, 2007 and 2006, the Company has approximately $307.2 million and
$291.1 million, respectively, in regulatory liabilities. Of these
amounts, $288.3 million and $270.6 million relate to cost of removal
obligations.
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).
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.
|
I.
|
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). SFAS 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. 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.
ARO’s
included in Other
liabilities total $18.8 million and $20.8 million at December 31, 2007
and 2006, respectively. At December 31, 2007, a $9.5 million ARO is
included in Accrued
liabilities. During 2007, the Company recorded accretion of
$1.2 million and increases in estimates of $6.3 million. During 2006,
the Company recorded accretion of $1.2 million and reductions in estimates of
totaling $1.2 million.
|
J.
|
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.
-61-
|
K.
|
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:
|
2005
|
2006
|
2007
|
||||||||||||||||||||||||||
|
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
|
$ |
4.1
|
$ | (4.6 | ) | $ | (0.5 | ) | $ |
10.7
|
$ |
10.2
|
$ |
11.0
|
$ |
21.2
|
||||||||||||
|
Pension
& other benefit costs
|
(29.3 | ) |
0.3
|
(29.0 | ) |
26.5
|
(2.5 | ) |
1.2
|
(1.3 | ) | |||||||||||||||||
|
Cash
flow hedges
|
-
|
6.7
|
6.7
|
(6.0 | ) |
0.7
|
(0.1 | ) |
0.6
|
|||||||||||||||||||
|
Deferred
income taxes
|
10.2
|
(1.0 | ) |
9.2
|
(12.5 | ) | (3.3 | ) | (4.7 | ) | (8.0 | ) | ||||||||||||||||
|
Accumulated
other
comprehensive income
(loss)
|
$ | (15.0 | ) | $ |
1.4
|
$ | (13.6 | ) | $ |
18.7
|
$ |
5.1
|
$ |
7.4
|
$ |
12.5
|
||||||||||||
Accumulated other comprehensive income arising from unconsolidated affiliates is primarily the Company’s portion of ProLiance Holdings, 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.)
|
L.
|
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.
|
M.
|
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 $41.8 million in 2007, $39.7
million in 2006, and $42.6 million in 2005. Expense associated with
excise and utility receipts taxes are recorded as a component of Taxes other than income
taxes.
|
N.
|
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.
|
O.
|
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. For the year ended December 31,
2005 the effect on net income and earnings per share as if the fair value based
method prescribed in SFAS 123 had been applied to stock option grants
follows:
|
Year
Ended
|
||||
|
December
31,
|
||||
|
(In millions, except per share
amounts)
|
2005
|
|||
|
Net
Income as reported:
|
$ |
136.8
|
||
|
Share-based
employee compensation included in reported net income-net of
tax
|
2.1
|
|||
|
Total
share-based employee compensation expense determined under fair
value
|
||||
|
based
method for all awards-net of tax
|
(2.8 | ) | ||
|
Pro forma net
income
|
$ |
136.1
|
||
|
Basic
earnings per share as reported:
|
$ |
1.81
|
||
|
Basic
earnings per share pro forma:
|
1.80
|
|||
|
Diluted
earnings per share as reported:
|
$ |
1.80
|
||
|
Diluted
earnings per share pro forma:
|
1.79
|
|||
|
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 (See Note 17). 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)
|
2007
|
2006
|
||||||
|
ProLiance
Energy, LLC
|
$ |
178.6
|
$ |
146.7
|
||||
|
Haddington
Energy Partnerships
|
13.8
|
13.8
|
||||||
|
Other
partnerships & corporations
|
16.4
|
20.5
|
||||||
|
Total investments in
unconsolidated affiliates
|
$ |
208.8
|
$ |
181.0
|
||||
ProLiance Holdings,
LLC
ProLiance
Holdings, 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
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. Consistent with its ownership percentage, Vectren is
allocated 61 percent of ProLiance’s profits and losses; however, governance and
voting rights remain at 50 percent for each member; and therefore, the Company
accounts for its investment in ProLiance using the equity method of
accounting. The Company, including its retail gas supply operations,
contracted for 75 percent of its natural gas purchases through ProLiance in 2007
and 2006.
Summarized Financial
Information
|
Year
Ended December 31,
|
||||||||||||
|
(in
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Summarized
Statement of Income information:
|
||||||||||||
|
Revenues
|
$ |
2,267.1
|
$ |
2,505.5
|
$ |
3,237.0
|
||||||
|
Margin
|
97.4
|
105.9
|
116.0
|
|||||||||
|
Operating
income
|
61.5
|
55.0
|
87.1
|
|||||||||
|
ProLiance's
earnings
|
67.2
|
57.9
|
86.0
|
|||||||||
|
As
of December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Summarized
balance sheet information:
|
||||||||
|
Current
assets
|
$ |
684.3
|
$ |
652.4
|
||||
|
Noncurrent
assets
|
45.2
|
41.5
|
||||||
|
Current
liabilities
|
436.9
|
453.7
|
||||||
|
Noncurrent
liabilities
|
4.3
|
4.2
|
||||||
|
Equity
|
288.3
|
236.1
|
||||||
Vectren’s
share of ProLiance’s earnings, after income taxes, allocated interest expense,
and other income was $22.9 million, $18.3 million, and $31.1 million for the
years ended December 31, 2007, 2006, and 2005, respectively.
Transactions with
ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2007, 2006, and 2005, totaled $792.4 million, $777.0 million, and
$1,049.3 million, respectively. Amounts owed to ProLiance at December
31, 2007, and 2006, for those purchases were $81.5 million and $84.8 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.
Regulatory
Matter
ProLiance
self reported to the Federal Energy Regulatory Commission (FERC or the
Commission) in October 2007 possible non-compliance with the Commission’s
capacity release policies. ProLiance has taken corrective actions to
assure that current and future transactions are compliant. ProLiance is
committed to full regulatory compliance and is cooperating fully with the FERC
regarding these issues. ProLiance is unable to predict the outcome of any
FERC action.
ProLiance Lawsuit
Settlement
On
November 22, 2006, ProLiance settled a 2002 civil lawsuit between the City of
Huntsville, Alabama and ProLiance. The $21.6 million settlement
related to a dispute over a contractual relationship with Huntsville Utilities
during 2000-2002.
During
2006, ProLiance recorded an $18.3 million charge recognizing the
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.
Haddington Energy
Partnerships
The
Company has an approximate 40 percent 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, 2007, the Company has no further commitments to invest in either
Haddington I or II. As of December 31, 2007, 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.
The
following is summarized financial information as to the assets, liabilities, and
results of operations of Haddington. For the year ended December 31,
2007, revenues, operating loss, and net loss were (in millions) zero, $(0.4),
and $(0.3), respectively. 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. As of December 31, 2007, investments, other assets, and
liabilities were (in millions) $31.3, $1.1, and zero,
respectively. As of December 31, 2006, investments, other assets, and
liabilities were (in millions) $31.3, $1.0, 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 provided 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, received processing fees from synfuel producers unrelated to Pace Carbon
for a portion of its coal production. The tax law authorizing synfuel
related credits and fees expired on December 31, 2007.
The
Internal Revenue Service issued private letter rulings, which concluded 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. Generally, the statute
of limitations for the IRS to audit a tax return is three years from filing.
Therefore tax credits utilized in 2004 – 2007 are still subject to IRS
examination. However, avenues remain where the IRS could challenge tax credits
of pre-2004 years.
As a
partner of Pace Carbon, Vectren has reflected synfuel tax credits in its
consolidated results from inception through December 31, 2007 of approximately
$99 million, of which approximately $60 million have been generated since 2003.
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 has an Alternative Minimum Tax (AMT) credit carryforward of
approximately $35.7 million at December 31, 2007.
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 74 percent phase out in
2007. Therefore, of the $23.1 million tax credits generated in 2007,
only $6.0 million are reflected as a reduction to the Company’s income tax
expense. In 2006 high oil prices resulted in a 35 percent phase out
of synfuel tax credits. 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.
Since
2005, the Company executed several financial contracts to hedge oil price
risk. Income statement activity associated with these contracts was
gain of $13.4 million in 2007, a loss of $4.7 million in 2006 and a loss of $1.9
million in 2005. This activity is reflected in Other-net. Impairment
charges related to the investment in Pace Carbon approximating $9.5 million were
recorded in Other-net
in 2006.
Synfuel-related
results, inclusive of equity method losses and their related tax benefits as
well as the tax credits and other related activity, were earnings of $6.8
million in 2007, compared to a loss of $5.3 million in 2006 and earnings of
$11.7 million in 2005.
The
following is summarized financial information as to the assets, liabilities, and
results of operations of Pace Carbon. For the year ended December 31,
2007, revenues, margin, operating loss, and net loss were (in millions) $471.1,
($139.7), ($158.8), and ($240.2), respectively. 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. As of December 31, 2007, current assets, noncurrent
assets, current liabilities, and noncurrent liabilities were (in millions)
$65.3, $67.3, $50.8, and $48.6, 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.
Utilicom Networks, LLC &
Related Entities
The
Company had an approximate 2 percent equity interest and a convertible
subordinated debt investment in Utilicom Networks, LLC
(Utilicom). The Company also had an approximate 19 percent equity
interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to
hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provided 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.
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 includes the settlement of notes receivable, approximated $45 million and
were received in 2007.
Undistributed Earnings of
Unconsolidated Affiliates
As of
December 31, 2007, undistributed earnings of unconsolidated affiliates
approximated $158 million and are primarily comprised of the undistributed
earnings of ProLiance.
|
4.
|
Miller Pipeline Corporation
Acquisition in 2006
|
Effective
July 1, 2006, the Company purchased the remaining 50 percent 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 has not been material to the overall financial statements,
consolidating Miller resulted in, among other impacts, increases in Nonutility revenue totaling
$105.7 million in 2007 compared to 2006 and $77.6 million
in 2006 compared to 2005; and increases in Other operating expense
totaling $90.9 million in 2007 compared to 2006 and $60.8 million in 2006
compared to 2005. 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. Of the $31 million of goodwill, approximately $0.9
million is not deductible for tax purposes.
Prior to
this transaction, Miller was 100 percent owned by Reliant Services, LLC
(Reliant). Reliant, a 50 percent 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. In 2007, fees paid to
Reliant were less than $0.1 million. For the years ended December 31,
2006, and 2005, fees paid to Reliant for locating and meter reading services as
well as for Miller’s construction-related services totaled $20.6 million, and
$21.3 million, respectively. Amounts charged are market
based. Amounts owed to Reliant totaled less than $0.1 million at both
December 31, 2007 and 2006 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)
|
2007
|
2006
|
||||||
|
Leveraged
leases
|
$ |
30.3
|
$ |
31.0
|
||||
|
Cash
surrender value of life insurance policies (See Note 7)
|
18.2
|
16.6
|
||||||
|
Other
investments
|
28.5
|
26.9
|
||||||
|
Total other
investments
|
$ |
77.0
|
$ |
74.5
|
||||
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, 2007, and
2006, 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 $46.7
million and $47.4 million at December 31, 2007, and 2006,
respectively. At December 31, 2007 and 2006, the Company’s leveraged
lease investment, net of related deferred tax liabilities, was $11.0 million and
$10.2 million, respectively.
Other
Investments
Other
investments include notes receivable, restricted cash, and a municipal bond,
among other items.
|
6.
|
Income
Taxes
|
The
components of income tax expense and utilization of investment tax credits
follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ |
35.9
|
$ |
18.2
|
$ |
37.9
|
||||||
|
State
|
13.1
|
10.7
|
14.8
|
|||||||||
|
Total current
taxes
|
49.0
|
28.9
|
52.7
|
|||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
24.6
|
7.0
|
(6.0 | ) | ||||||||
|
State
|
4.1
|
(3.6 | ) | (0.2 | ) | |||||||
|
Total deferred
taxes
|
28.7
|
3.4
|
(6.2 | ) | ||||||||
|
Amortization
of investment tax credits
|
(1.7 | ) | (2.0 | ) | (2.4 | ) | ||||||
|
Total income tax
expense
|
$ |
76.0
|
$ |
30.3
|
$ |
44.1
|
||||||
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)
|
2007
|
2006
|
||||||
|
Noncurrent
deferred tax liabilities (assets):
|
||||||||
|
Depreciation
& cost recovery timing differences
|
$ |
310.2
|
$ |
297.0
|
||||
|
Leveraged
leases
|
19.3
|
20.8
|
||||||
|
Regulatory
assets recoverable through future rates
|
20.3
|
21.0
|
||||||
|
Demand
side management programs
|
7.9
|
8.4
|
||||||
|
Other
comprehensive income
|
7.2
|
2.5
|
||||||
|
Alternative
minimum tax carryforward
|
(3.4 | ) | (42.1 | ) | ||||
|
Employee
benefit obligations
|
(34.5 | ) | (39.2 | ) | ||||
|
Net
operating loss & other carryforwards
|
(4.1 | ) | (10.1 | ) | ||||
|
Regulatory
liabilities to be settled through future rates
|
(6.3 | ) | (7.7 | ) | ||||
|
Other –
net
|
1.5
|
10.1
|
||||||
|
Net
noncurrent deferred tax liability
|
318.1
|
260.7
|
||||||
|
Current
deferred tax (assets)/liabilities:
|
||||||||
|
Deferred fuel
costs-net
|
(1.2 | ) | (1.8 | ) | ||||
|
Alternative
minimum tax carryforward
|
(29.6 | ) |
-
|
|||||
|
Other –
net
|
0.9
|
(1.8 | ) | |||||
|
Net
current deferred tax (asset)/liability
|
(29.9 | ) | (3.6 | ) | ||||
|
Net deferred
tax liability
|
$ |
288.2
|
$ |
257.1
|
||||
At December 31, 2007, and 2006, investment tax credits totaling $8.2 million and $9.9 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, 2007, the Company has alternative minimum tax carryforwards of $33.0 million, which do not expire. In addition, the Company has $4.0 million in net operating loss carryforwards that relate to the acquisition of Miller, which will expire in 5 to 20 years.
A
reconciliation of the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Statutory
rate:
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State
and local taxes-net of federal benefit
|
4.3
|
5.7
|
5.5
|
|||||||||
|
Synfuel
tax credits
|
(3.0 | ) | (9.6 | ) | (12.3 | ) | ||||||
|
Adjustment of
income tax accruals
|
(0.7 | ) | (2.0 | ) | (1.9 | ) | ||||||
|
Tax law
change
|
0.2
|
(2.5 | ) |
-
|
||||||||
|
Amortization of
investment tax credit
|
(0.8 | ) | (1.4 | ) | (1.3 | ) | ||||||
|
Depletion
|
(0.7 | ) | (1.6 | ) | (1.0 | ) | ||||||
|
Other
tax credits
|
(0.2 | ) | (0.5 | ) | (0.4 | ) | ||||||
|
All
other-net
|
0.6
|
(1.3 | ) |
0.8
|
||||||||
|
Effective tax
rate
|
34.7 | % | 21.8 | % | 24.4 | % | ||||||
Accounting for Uncertainty in Income Taxes
On
January 1, 2007, the Company adopted 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.
As a
result of the implementation of FIN 48, the Company recognized an approximate
$0.3 million increase in the liability for unrecognized tax benefits, of which
$0.1 million was accounted for as a reduction to the January 1, 2007, balance of
Retained earnings and
$0.2 million was recorded as an increase to Goodwill. At
adoption, the total amount of gross unrecognized tax benefits was $11.6
million.
Following
is a reconciliation of the total amount of unrecognized tax benefits as of
December 31, 2007:
|
(in
millions)
|
||||
|
Unrecognized
tax benefits at 1/1/2007
|
$ |
11.6
|
||
|
Gross
Increases - tax positions in prior periods
|
0.3
|
|||
|
Gross
Decreases - tax positions in prior periods
|
(7.4 | ) | ||
|
Gross
Increases - current period tax positions
|
1.9
|
|||
|
Gross
Decreases - current period tax positions
|
(0.2 | ) | ||
|
Unrecognized tax benefits at December 31, 2007
|
$ |
6.2
|
||
Of the
change in unrecognized tax benefits during 2007 of $5.4 million, $3.1 million
impacted the effective tax rate. The amount of unrecognized tax
benefits, which, if recognized, that would impact the effective tax rate as of
December 31, 2007, was $0.1 million. The remaining unrecognized tax
benefit relates to tax positions for which the ultimate deductibility is highly
certain but for which there is uncertainty about the timing of such
deductibility. Because of the impact of deferred tax accounting, other
than interest and penalties, the disallowance of the shorter deductibility
period would not affect the annual effective tax rate but would accelerate the
payment of cash to the taxing authority.
The
Company accrues interest and penalties associated with unrecognized tax benefits
in Income taxes.
During the year ended December 31, 2007, the Company recognized expense related
to interest and penalties totaling approximately $0.5 million. During
the years ended December 31, 2006 and 2005, the Company recognized expense
related to interest and penalties of less than $1 million in both
years. The Company had approximately $0.8 million and $1.9 million
for the payment of interest and penalties accrued as of December 31, 2007 and
December 31, 2006, respectively.
The
liability included in Other
liabilities on the Consolidated Balance Sheet for unrecognized tax
benefits inclusive of interest, penalties and net of secondary impacts, which
are benefits, totaled $2.5 million at December 31, 2007.
From time
to time, the Company may consider changes to filed positions that could impact
its unrecognized tax benefits. However, it is not expected that such
changes would have a significant impact on earnings and would only affect the
timing of payments to taxing authorities.
The
Company and/or certain of its subsidiaries file income tax returns in the U.S.
federal jurisdiction and various states. The Internal Revenue Service
(IRS) has conducted examinations of the Company’s U.S. federal income tax
returns for tax years through December 31, 2004. The State of Indiana, the
Company’s primary state tax jurisdiction, has conducted examinations of state
income tax returns for tax years through December 31, 2002. On February
15, 2008, the Company was notified by the IRS of their intent to perform a
limited scope examination of the Company’s 2005 consolidated tax
return.
|
7.
|
Retirement Plans & Other
Postretirement Benefits
|
At
December 31, 2007, 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. 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, 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 required 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. On January 1, 2008, the Company
recorded a $2.7 million reduction to retained earnings to move the measurement
date from September 30 to December 31.
Benefit
Obligations
A
reconciliation of the Company’s benefit obligations at December 31, 2007 and
2006, follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2007
|
2006
|
||||||||||||
|
Benefit
obligation, beginning of period
|
$ |
255.4
|
$ |
255.4
|
$ |
69.5
|
$ |
72.0
|
||||||||
|
Service
cost – benefits earned during the period
|
5.6
|
6.0
|
0.5
|
0.6
|
||||||||||||
|
Interest
cost on projected benefit obligation
|
14.9
|
14.1
|
3.9
|
3.9
|
||||||||||||
|
Plan
participants' contributions
|
-
|
-
|
1.3
|
1.7
|
||||||||||||
|
Plan
amendments
|
-
|
2.1
|
-
|
-
|
||||||||||||
|
Actuarial
loss (gain)
|
(13.9 | ) | (10.2 | ) |
1.5
|
(0.4 | ) | |||||||||
|
Medicare
subsidy receipts
|
-
|
-
|
0.2
|
0.3
|
||||||||||||
|
Benefits
paid
|
(12.4 | ) | (12.0 | ) | (6.7 | ) | (8.6 | ) | ||||||||
|
Benefit obligation, end of
period
|
$ |
249.6
|
$ |
255.4
|
$ |
70.2
|
$ |
69.5
|
||||||||
The accumulated benefit obligation for all defined benefit pension plans was $231.9 million and $234.8 million at December 31, 2007 and 2006, respectively.
The
benefit obligation as of December 31, 2007 and 2006 was calculated using the
following assumptions:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
2007
|
2006
|
2007
|
2006
|
|||||||||||||
|
Discount
rate
|
6.25 | % | 5.85 | % | 6.25 | % | 5.85 | % | ||||||||
|
Rate
of compensation increase
|
3.75 | % | 3.75 | % |
N/A
|
N/A
|
||||||||||
|
Expected
increase in Consumer Price Index
|
N/A
|
N/A
|
3.50 | % | 3.50 | % | ||||||||||
To
calculate the 2007 ending postretirement benefit obligation, medical claims
costs in 2008 were assumed to be 8 percent higher than those incurred in
2007. That trend was assumed to gradually decline to 5 percent over a
three 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 2006
ending postretirement benefit obligation, medical claims costs in 2007 were
assumed to be 9 percent higher than those incurred in 2006. That
trend was assumed to gradually decline to 5 percent over a four year period and
to remain level thereafter.
Plan
Assets
A
reconciliation of the Company’s plan assets at December 31, 2007 and 2006
follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2007
|
2006
|
||||||||||||
|
Plan
assets at fair value, beginning of period
|
$ |
185.0
|
$ |
173.6
|
$ |
6.8
|
$ |
7.4
|
||||||||
|
Actual
return on plan assets
|
22.3
|
14.8
|
0.9
|
0.3
|
||||||||||||
|
Employer
contributions
|
16.9
|
8.6
|
4.5
|
6.0
|
||||||||||||
|
Plan
participants' contributions
|
-
|
-
|
1.3
|
1.7
|
||||||||||||
|
Benefits
paid
|
(12.4 | ) | (12.0 | ) | (6.7 | ) | (8.6 | ) | ||||||||
|
Fair value of plan assets, end
of period
|
$ |
211.8
|
$ |
185.0
|
$ |
6.8
|
$ |
6.8
|
||||||||
The asset
allocation for the Company's pension and postretirement plans at the measurement
date for 2007 and 2006 by asset category follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
2007
|
2006
|
2007
|
2006
|
|||||||||||||
|
Equity
securities
|
64 | % | 62 | % | 74 | % | 65 | % | ||||||||
|
Debt
securities
|
31 | % | 33 | % | 26 | % | 31 | % | ||||||||
|
Real
estate and other
|
5 | % | 5 | % |
-
|
4 | % | |||||||||
|
Total
|
100 | % | 100 | % | 100 | % | 100 | % | ||||||||
The
Company invests in trusts that benefit its qualified defined benefit
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 percent equities, 35 percent debt, and 5
percent for other asset classes, including real estate for 2007, and for
postretirement plans of 65 percent equities, 30 percent debt, and 5 percent
short-term investments for 2007. 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 as of December 31, 2007 and 2006
follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2007
|
2006
|
||||||||||||
|
Benefit
obligation, end of period
|
$ |
249.6
|
$ |
255.4
|
$ |
70.2
|
$ |
69.5
|
||||||||
|
Fair
value of plan assets, end of period
|
(211.8 | ) | (185.0 | ) | (6.8 | ) | (6.8 | ) | ||||||||
|
Post
measurement date adjustments
|
(2.4 | ) | (1.2 | ) | (1.1 | ) | (1.1 | ) | ||||||||
|
Funded status, end of
period:
|
$ |
35.4
|
$ |
69.2
|
$ |
62.3
|
$ |
61.6
|
||||||||
|
Accrued
liabilities
|
$ |
0.7
|
$ |
0.7
|
$ |
3.9
|
$ |
5.5
|
||||||||
|
Other
liabilities
|
$ |
34.7
|
$ |
68.5
|
$ |
58.4
|
$ |
58.4
|
||||||||
As of
December 31, 2007 and 2006, the funded status of the SERP, which is included in
Pension Benefits in the chart above, was an unfunded amount of $13.1 million and
$13.4 million, respectively.
Net Periodic Benefit
Costs
A summary
of the components of net periodic benefit cost for the three years ended
December 31, 2007, follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
2007
|
2006
|
2005
|
||||||||||||||||||
|
Service
cost
|
$ |
5.6
|
$ |
6.0
|
$ |
5.6
|
$ |
0.5
|
$ |
0.6
|
$ |
0.7
|
||||||||||||
|
Interest
cost
|
14.9
|
14.1
|
13.8
|
4.0
|
3.9
|
4.5
|
||||||||||||||||||
|
Expected
return on plan assets
|
(14.3 | ) | (13.5 | ) | (13.2 | ) | (0.5 | ) | (0.6 | ) | (0.6 | ) | ||||||||||||
|
Amortization
of prior service cost
|
1.7
|
1.8
|
1.6
|
(0.8 | ) | (0.8 | ) | (0.6 | ) | |||||||||||||||
|
Amortization
of actuarial loss (gain)
|
1.5
|
2.4
|
1.8
|
(0.1 | ) |
-
|
(0.2 | ) | ||||||||||||||||
|
Amortization
of transitional obligation
|
-
|
-
|
-
|
1.1
|
1.1
|
1.5
|
||||||||||||||||||
|
Net periodic benefit
cost
|
$ |
9.4
|
$ |
10.8
|
$ |
9.6
|
$ |
4.2
|
$ |
4.2
|
$ |
5.3
|
||||||||||||
A portion
of benefit costs are capitalized as Utility
plant. Costs capitalized in 2007, 2006, and 2005 approximated
$3.9 million, $4.3 million, and $4.2 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 percent equity, 35 percent debt, and 5 percent alternative
investments allocation for the pension plans, the Company has used a long-term
expected rate of return of 8.25 percent to calculate 2007 periodic benefit
cost. For fiscal 2008, the expected long-term rate of return will
also be 8.25 percent.
The
Company has increased the discount rate used to measure its benefit obligations
and periodic cost due to increases in benchmark interest rates that approximate
the expected duration of the Company’s benefit obligations. For
fiscal 2008, the discount rate will be 6.25 percent.
The
weighted averages of significant assumptions used to determine net periodic
benefit costs follow:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
2007
|
2006
|
2005
|
||||||||||||||||||
|
Discount
rate
|
5.85 | % | 5.50 | % | 5.75 | % | 5.85 | % | 5.50 | % | 5.75 | % | ||||||||||||
|
Rate
of compensation increase
|
3.75 | % | 3.25 | % | 3.50 | % |
N/A
|
N/A
|
N/A
|
|||||||||||||||
|
Expected
return on plan assets
|
8.25 | % | 8.25 | % | 8.25 | % | 8.25 | % | 8.25 | % | 8.25 | % | ||||||||||||
|
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.
Prior Service Cost,
Actuarial Gains and Losses, and Transition Obligation
Effects
Following
is a reconciliation of the amounts in accumulated other comprehensive income
(AOCI) and regulatory assets related to retirement plan obligations at December
31, 2007 and 2006:
|
(In
millions)
|
2007
|
2006
|
||||||||||||||
|
Pensions
|
Other
Benefits
|
Pensions
|
Other
Benefits
|
|||||||||||||
|
Prior
service cost
|
$ |
11.2
|
$ | (4.7 | ) | $ |
12.9
|
$ | (5.5 | ) | ||||||
|
Unamortized
actuarial gain/(loss)
|
11.9
|
(1.1 | ) |
35.3
|
(2.2 | ) | ||||||||||
|
Transition
obligation
|
-
|
7.6
|
-
|
8.7
|
||||||||||||
|
23.1
|
1.8
|
48.2
|
1.0
|
|||||||||||||
|
Less:
Regualtory asset
deferral
|
(21.9 | ) | (1.7 | ) | (45.8 | ) | (0.9 | ) | ||||||||
|
AOCI before
taxes
|
$ |
1.2
|
$ |
0.1
|
$ |
2.4
|
$ |
0.1
|
||||||||
A roll
forward of these amounts identifying those components reclassified to periodic
cost and those components arising during the year since adoption of SFAS 158
follows:
|
(In
millions)
|
Pensions
|
Other
Benefits
|
||||||||||||||||||
|
Prior
Service
Cost
|
Net
Gain or
Loss
|
Prior
Service
Cost
|
Net
Gain or
Loss
|
Transition
Obligation
|
||||||||||||||||
|
Balance
at adoption of SFAS 158
|
$ |
12.9
|
$ |
35.3
|
$ | (5.5 | ) | $ | (2.2 | ) | $ |
8.7
|
||||||||
|
Amounts
arising during the period
|
(21.9 | ) |
-
|
1.2
|
-
|
|||||||||||||||
|
Reclassification
to benefit costs
|
(1.7 | ) | (1.5 | ) |
0.8
|
(0.1 | ) | (1.1 | ) | |||||||||||
|
Balance December 31,
2007
|
$ |
11.2
|
$ |
11.9
|
$ | (4.7 | ) | $ | (1.1 | ) | $ |
7.6
|
||||||||
Related
to pension plans, $1.7 million of prior service cost and $0.1 million of
actuarial gain/loss is expected to be amortized to periodic cost in
2008. Related to other benefits, $1.1 million of the transition
obligation is expected to be amortized to periodic cost in 2008, and $0.8
million of prior service cost is expected to reduce periodic cost in
2008.
Expected Cash
Flows
In 2008,
the Company expects to make contributions of approximately $10 million to its
pension plan trusts. In addition, the Company expects to make
payments totaling approximately $1 million directly to SERP participants and
approximately $5 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 2007 (in millions) are $13.6 in 2008, $14.4 in 2009
$14.6 in 2010, $16.0 in 2011, $16.4 in 2012 and $95.1 in years
2013-2017. Expected benefit payments projected to be required for
postretirement benefits during the years following 2007 (in millions) are $6.4
in 2008, $7.1 in 2009, $7.5 in 2010, $7.8 in 2011, and $8.0 in 2012 and $44.0 in
years 2013-2017.
Defined Contribution
Plan
The
Company also has defined contribution retirement savings plans that are
qualified under sections 401(a) and 401(k) of the Internal Revenue
Code. During 2007, 2006 and 2005, the Company made contributions to
these plans of $4.0 million, $3.9 million, and $3.5 million,
respectively.
Deferred Compensation
Plans
The
Company has nonqualified deferred compensation plans, which permit eligible
executives and non-employee directors to defer portions of their compensation
and vested restricted stock. A record keeping account is established for
each participant, and the participant chooses from a variety of measurement
funds for the deemed investment of their accounts. The measurement funds
are similar to the funds in the Company's defined contribution plan and include
an investment in phantom stock units of the Company. The account balance
fluctuates with the investment returns on those funds. At December 31,
2007 and 2006, the liability associated with these plans totaled $29.0 million
and $27.6 million, respectively, and is included in Deferred credits and other
liabilities. Deferred compensation expense was $2.2 million, $0.7
million and $2.6 million in 2007, 2006, and 2005,
respectively.
The
Company has established certain investments to fund its deferred compensation
liabilities that are currently funded primarily through corporate-owned life
insurance policies. These investments, which are consolidated, are
available to pay plan benefits and are subject to the claims of the Company's
creditors. The cash surrender value of these policies included in
Other investments on
the Consolidated Balance Sheets were $18.2 million and $16.6 million at December
31, 2007 and 2006, respectively. Earnings from those investments totaled
$0.6 million in 2007, $0.8 million in 2006, and $1.8 million in
2005.
|
8.
|
Borrowing
Arrangements
|
Short-Term
Borrowings
At
December 31, 2007, the Company has $780.0 million of short-term borrowing
capacity, including $520.0 million for the Utility Group operations and $260.0
million for the wholly owned Nonutility Group and corporate operations, of which
approximately $134 million is available for the Utility Group operations and
approximately $89 million is available for wholly owned Nonutility Group and
corporate operations. These 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)
|
2007
|
2006
|
2005
|
|||||||||
|
Weighted
average commercial paper and bank loans outstanding
during the year
|
$ |
391.3
|
$ |
256.1
|
$ |
304.5
|
||||||
|
Weighted average interest rates during the year
|
||||||||||||
|
Commercial paper
|
5.54 | % | 5.16 | % | 3.42 | % | ||||||
|
Bank loans
|
5.61 | % | 5.51 | % | 3.82 | % | ||||||
|
At
December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
||||||||||
|
Commercial
paper
|
$ |
385.9
|
$ |
270.1
|
||||||||
|
Bank
loans
|
171.1
|
194.7
|
||||||||||
|
Total short-term
borrowings
|
$ |
557.0
|
$ |
464.8
|
||||||||
Long-Term Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
|||||||||||
|
(In
millions)
|
2007
|
2006
|
|||||||||
|
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
|
|||||||||
|
2035,6.10%
|
75.0
|
75.0
|
|||||||||
|
l036,5.95%
|
100.0
|
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 4.00%, tax
exempt,
|
|||||||||||
|
auction rate
mode, 2007 weighted average: 3.83%
|
9.8
|
9.8
|
|||||||||
|
2023,
1993 Environmental Improvement Series B, current adjustable rate
4.61%,
|
|||||||||||
|
tax
exempt, auction rate mode, 2007 weighted average: 4.13%
|
22.6
|
22.6
|
|||||||||
|
2025,
1998 Pollution Control Series A, current adjustable rate 4.00%, tax
exempt,
|
|||||||||||
|
auction rate
mode, 2007 weighted average: 3.90%
|
31.5
|
31.5
|
|||||||||
|
2030,
1998 Pollution Control Series C, current adjustable rate 4.77%, tax
exempt,
|
|||||||||||
|
auction
rate mode, 2007 weighted average: 4.15%
|
22.2
|
22.2
|
|||||||||
|
2041,
2007 Pollution Control Series, current adjustable rate 5.22%, tax
exempt,
|
|||||||||||
|
auction
rate mode, 2007 weighted average: 4.80%
|
17.0
|
-
|
|||||||||
|
Total
SIGECO
|
245.2
|
228.2
|
|||||||||
|
Indiana
Gas
|
|||||||||||
|
Senior Unsecured Notes
|
|||||||||||
|
2007,
Series E, 6.54%
|
-
|
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
|
$ |
121.0
|
$ |
127.5
|
|||||||
|
At
December 31,
|
|||||
|
(In
millions)
|
2007
|
2006
|
|||
|
Vectren Capital
Corp.
|
|||||
|
Fixed
Rate Senior Unsecured Notes
|
|||||
|
2007,
7.83%
|
$ -
|
$ 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.
|
182.5
|
200.0
|
|||
|
Other
Long-Term Notes Payable
|
0.3
|
0.6
|
|||
|
Total long-term debt
outstanding
|
1,249.0
|
1,256.3
|
|||
|
Current
maturities of long-term debt
|
(0.3)
|
(24.2)
|
|||
|
Debt
subject to tender
|
-
|
(20.0)
|
|||
|
Unamortized
debt premium & discount - net
|
(3.3)
|
(3.8)
|
|||
|
Fair
value of hedging arrangements
|
-
|
(0.3)
|
|||
|
Total long-term
debt-net
|
$ 1,245.4
|
$
1,208.0
|
|||
SIGECO Pollution Control
Bonds
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt has a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate will be reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation.
Utility Holdings 2006
Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95 percent 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 percent 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
percent priced at 99.799 percent to yield 5.47 percent to maturity (2015
Notes). The second tranche was 30-year notes due December 2035 with
an interest rate of 6.10 percent priced at 99.799 percent to yield 6.11 percent
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 percent 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 percent Guaranteed Senior Notes, Series A due 2010, (ii) $25
million 5.13 percent Guaranteed Senior Notes, Series B due 2012 and (iii) $75
million 5.31 percent 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 percent.
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 percent Senior Notes due 2005, (ii)
$17.5 million 7.83 percent Senior Notes due 2007, (iii) $22.5 million 7.98
percent 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 percent 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) replace a more limited support
agreement with an unconditional guarantee by Vectren and (iv) provide for a 100
basis point increase in interest rates if the ratio of consolidated total debt
to total capitalization exceeds 65 percent.
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 2007, 2006 and
2005, no debt was put to the Company. Debt which may be put to the
Company during the years following 2007 (in millions) is zero in 2008, $80.0 in
2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. Debt
that may be put to the Company within one year is classified as Long-term debt subject to
tender in current liabilities.
In
February 2008, SIGECO began the process of providing notice to the current
holders of approximately $103 million of tax exempt auction rate mode long term
debt that the Company will convert that debt from its current auction rate mode
into a daily interest rate mode during March 2008. The debt will be
subject to mandatory tender for purchase on the conversion date at 100 percent
of the principal amount plus accrued interest.
Utility Holdings 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 senior unsecured notes originally due in
2030. The notes called in 2006 and 2005 had stated interest rates of
7.25 percent and 7.45 percent, 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 percent to 5.00 percent. After the remarketing,
interest rates are reset every seven days using an auction
process.
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 $24.0 million in 2007 and $38.0 million in 2005 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
percent 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, 2007, $836.7 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 $2.2 billion at December 31,
2007.
Consolidated
maturities of long-term debt during the five years following 2007 (in millions)
are zero in 2008 and in 2009, $47.5 in 2010, $250.0 in 2011, and $60.0 in
2012.
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, 2007, 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 $183 million and $171 million, respectively, at December 31,
2007. 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, 2007, totaled $700 million and $386 million,
respectively.
|
9.
|
Share-Based
Compensation
|
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)
|
2007
|
2006
|
2005
|
|||||||||
|
Total
cost of share-based compensation
|
$ |
2.5
|
$ |
3.2
|
$ |
4.5
|
||||||
|
Less
capitalized cost
|
0.5
|
0.9
|
1.0
|
|||||||||
|
Total
in other operating expense
|
2.0
|
2.3
|
3.5
|
|||||||||
|
Less
income tax benefit in earnings
|
0.8
|
0.6
|
1.4
|
|||||||||
|
After
tax effect of share-based compensation
|
$ |
1.2
|
$ |
1.7
|
$ |
2.1
|
||||||
Restricted Stock Related
Matters
The
Company periodically grants executives and other key non-officer employees
restricted stock and/or restricted stock units 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 awards in
shares, cash, 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, 2007, and changes
during the year ended December 31, 2007, is presented below:
|
Equity
Awards
|
Liability
Awards
|
|||||||||||||||
|
Wtd.
Avg.
|
||||||||||||||||
|
Grant
Date
|
||||||||||||||||
|
|
Shares
|
Fair
value
|
Shares/units
|
Fair
value
|
|
|||||||||||
|
Restricted
at January 1, 2007
|
23,009
|
$ |
26.32
|
376,185
|
||||||||||||
|
Granted
|
13,030
|
29.18
|
181,788
|
|||||||||||||
|
Vested
|
(2,378 | ) |
24.88
|
(68,607 | ) | |||||||||||
|
Forfeited
|
(11,791 | ) |
27.16
|
(137,478 | ) | |||||||||||
|
Restricted
at December 31, 2007
|
21,870
|
$ |
28.11
|
351,888
|
$ 29.01
|
|||||||||||
As of
December 31, 2007, there was $6.1 million of total unrecognized compensation
cost related to restricted stock awards. That cost is expected to be
recognized over a weighted-average period of 2.9 years. The total fair
value of shares vested for awards to executives and non-employee directors
(Liability Awards) during the years ended December 31, 2007, 2006, and 2005, was
$1.9 million, $1.8 million, and $2.1 million, respectively. The total
fair value of shares vested for awards to key non-officer employees (Equity
Awards) during the year ended December 31, 2007, was $0.1 million. On
January 1, 2008, the Company granted 21,170 shares of restricted stock and
155,400 restricted stock units to executives and other key non-officer
employees.
Stock Option Related
Matters
Option
awards were 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 or 2007, and the Company does
not intend to issue options in 2008.
The fair
value of option awards granted in prior years was estimated on the date of grant
using a Black-Scholes option valuation model. 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
following weighted average assumptions used for grants in the year ended
December 31, 2005 were used: risk-free rate of return of 4.22 percent;
expected option term of 8 years; expected volatility of 21.43 percent; and
dividend yield of 4.4 percent. The
weighted average fair value of options granted in 2005 was
$4.36.
A summary
of the status of the Company’s stock option awards as of December 31, 2007, and
changes during the period ended December 31, 2007, follows:
|
Weighted
average
|
Aggregate
|
|||||||||||||||
|
Remaining
|
Intrinsic
|
|||||||||||||||
|
Shares
|
Exercise
|
Contractual
|
Value
|
|||||||||||||
|
Price
|
Term
(years)
|
(In
millions)
|
||||||||||||||
|
Outstanding
at January 1, 2007
|
1,963,985
|
$ |
23.33
|
|||||||||||||
|
Granted
|
-
|
-
|
||||||||||||||
|
Exercised
|
(526,015
|
) | $ |
21.90
|
||||||||||||
|
Forfeited
or expired
|
(5,196
|
) | $ |
21.27
|
||||||||||||
|
Outstanding
at December 31, 2007
|
1,432,774
|
$ |
23.86
|
5.0
|
$ |
7.4
|
||||||||||
|
Exercisable
at December 31, 2007
|
1,338,775
|
$ |
23.66
|
4.8
|
$ |
7.2
|
||||||||||
The total
intrinsic value of options exercised during the twelve months ended December 31,
2007, 2006, and 2005 was $3.6 million, $0.8 million, and $1.6 million,
respectively. As of December 31, 2007, there was less than $0.1
million of total unrecognized compensation cost related to vesting stock
options. That cost is expected to be recognized in
2008. The actual tax benefit realized for tax deductions from option
exercises was approximately $1.2 million in 2007, $0.2 million in 2006, and $0.1
million in 2005.
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, 2007, 2006, and 2005, the Company received
value upon exercise of stock options totaling approximately $11.4 million, $3.2
million, and $1.6 million, respectively. During those periods, the
Company repurchased shares totaling $6.9 million in 2007 and $3.8 million in
2006. No shares were purchased on the open market in
2005. 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, 2007, 2006
and 2005, was a cost of $0.4 million, and a benefit of $0.3 million and a cost
of $1.5 million, respectively.
|
10.
|
Common Shareholders’
Equity
|
Common Stock
Offering
In
February 2007, the Company sold 4.6 million authorized but previously unissued
shares of its common stock to a group of underwriters in an SEC-registered
primary offering at a price of $28.33 per share. The transaction
generated proceeds, net of underwriting discounts and commissions, of
approximately $125.7 million. The Company executed an equity forward
sale agreement (equity forward) in connection with the offering, and therefore,
did not receive proceeds at the time of the equity offering. The
equity forward allows the Company to price an offering under market conditions
existing at that time, and to better match the receipt of the offering proceeds
and the associated share dilution with the implementation of regulatory
initiatives, providing a return on the new equity employed. The
offering proceeds, when and if received, will be used to permanently finance
primarily electric utility capital expenditures.
In
connection with the equity forward, an affiliate of one of the underwriters (the
forward seller), at the Company's request, borrowed an equal number of shares of
the Company's common stock from institutional stock lenders and sold those
borrowed shares to the public in the primary offering. The Company
will receive an amount equal to the net proceeds from that sale, subject to
certain adjustments defined in the equity forward, upon full share settlement of
the equity forward. Those adjustments defined in the equity forward
include 1) daily increases in the forward sale price based on a floating
interest factor equal to the federal funds rate, less a 35 basis point
fixed spread, and 2) structured quarterly decreases to the forward sale price
that align with expected Company dividend payments.
The
Company may elect to settle the equity forward in shares or in cash, except in
specified circumstances or events where the counterparty to the equity forward
could force a share settlement. Examples of such events include, but
are not limited to, the Company making dividend payments greater than the
structured quarterly decreases identified in the equity forward or the Company
repurchasing a number of its outstanding common shares over a specified
threshold. If the Company elects to settle in shares, the maximum
number of shares deliverable by the Company is 4.6 million shares. If
the Company elects to settle in cash, an affiliate of one of the underwriters
(the forward purchaser) would purchase shares in the market and return those
shares to the stock lenders. The Company will either owe or be owed
funds depending upon the Company's average share price during the "unwind
period" defined in the equity forward in relation to the equity forward's
contracted price. Generally, if the equity forward's contracted price
is lower than average share price during the "unwind period", then the Company
would owe cash; and if the average share price during the "unwind period" is
less than the equity forward's contracted price, the Company would receive
cash. Proceeds received or paid when the equity forward is settled
will be recorded in Common
Shareholders' Equity, even if settled in cash. The equity
forward must be settled prior to February 28, 2009.
The
equity forward had an initial forward price of $27.34 per share, representing
the public offering price of $28.33 per share, net of underwriting discounts and
commissions. Management therefore estimated the contract had no
initial fair value. If the equity forward had been settled by
delivery of shares at December 31, 2007, the Company would have received
approximately $126.4 million based on a forward price of $27.47 for the 4.6
million shares. If the Company had elected to settle the equity
forward in cash at December 31, 2007, the Company estimates it would have paid
approximately $3 million, assuming the price in the “unwind period” approximates
the trailing three month average of Vectren’s stock price. The
federal funds rate was 4.50 percent at December 31, 2007. The
Company currently anticipates settling the equity forward by delivering
shares.
Authorized, Reserved Common
and Preferred Shares
At
December 31, 2007, and 2006, 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 6.3 million shares at December 31,
2007 and 7.2 million shares at December 31, 2006, 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, 2007,
and 2006, there were 396.4 million and 396.7 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. At December 31, 2007 available authorized common shares
include the 4.6 million shares related to the equity forward.
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 percent or more of the outstanding Vectren common shares (or a 10 percent
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 and settlement in shares of an equity forward
contract (see Note 10), using the treasury stock method, as well as the
conversion of restricted shares using the contingently issuable shares
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, 2007:
|
Year
Ended December 31,
|
||||||||||||
|
(In millions, except per share
data)
|
2007
|
2006
|
2005
|
|||||||||
|
Numerator:
|
||||||||||||
|
Numerator
for basic and diluted EPS - Net income
|
$ |
143.1
|
$ |
108.8
|
$ |
136.8
|
||||||
|
Denominator:
|
||||||||||||
|
Denominator
for basic EPS - Weighted average
|
||||||||||||
|
common
shares outstanding
|
75.9
|
75.7
|
75.6
|
|||||||||
|
Equity
forward dilution effect
|
0.1
|
-
|
-
|
|||||||||
|
Conversion
of stock options and lifting of
|
||||||||||||
|
restrictions
on issued restricted stock
|
0.6
|
0.5
|
0.5
|
|||||||||
|
Denominator
for diluted EPS - Adjusted weighted
|
||||||||||||
|
average
shares outstanding and assumed
|
||||||||||||
|
conversions
outstanding
|
76.6
|
76.2
|
76.1
|
|||||||||
|
Basic earnings per
share
|
$ |
1.89
|
$ |
1.44
|
$ |
1.81
|
||||||
|
Diluted earnings per
share
|
$ |
1.87
|
$ |
1.43
|
$ |
1.80
|
||||||
For the
years ended December 31, 2007, 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 2007 and thereafter (in millions) are $5.6 in 2008, $4.0 in 2009, $3.0
in 2010, $1.2 in 2011, $0.6 in 2012 and $0.7 thereafter. Total lease
expense (in millions) was $8.7 in 2007, $8.5 in 2006, and $6.1 in
2005.
Firm
purchase commitments for commodities by consolidated companies total (in
millions) $59.9 in 2008, $7.1 in 2009, $2.9 in 2010, 2011 and
2012. Firm purchase commitments for utility and nonutility plant
total (in millions) $36.6 in 2008, $4.0 in 2009, and zero in 2010, 2011 and
2012.
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,
2007, guarantees issued and outstanding on behalf of unconsolidated affiliates
approximated $3 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, 2007, Vectren Corporation has a liability
representing the fair value of that guarantee of less than $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/Climate
Change
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. However, on February 8, 2008, the US Court of Appeals for the
District of Columbia vacated the federal CAMR regulations. At this
time it is uncertain how this decision will affect Indiana’s recently finalized
CAMR implementation program.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990 and to further
comply with CAIR and CAMR of 2005, SIGECO has received authority from the IURC
to invest in clean coal technology. Using this authorization, SIGECO
invested approximately $258 million in Selective Catalytic Reduction (SCR)
systems at its coal fired generating stations. SCR technology is the most
effective method of reducing NOx emissions where high removal efficiencies are
required. To further reduce particulate matter emissions, the Company
invested approximately $49 million in a fabric filter at its largest generating
unit (287 MW). These investments were included in rate base for purposes
of determining new base rates that went into effect on August 15, 2007, (See
Note 14). Prior to being included in base rates, return on investments
made and recovery of related operating expenses were recovered through a rider
mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber at its
generating facility that is jointly owned with ALCOA (the Company’s portion is
150 MW). The order, as
updated with an increased spending level, allows SIGECO to recover an
approximate 8 percent return on up to $92 million, excluding AFUDC, in
capital investments through a rider mechanism which is updated every six months
for actual costs incurred. The Company may file periodic updates with
the IURC requesting modification to the spending authority. As of December
31, 2007, the Company has invested approximately $53 million in this
project. The Company expects the SO2 scrubber will be
operational in 2009. At that time, operating expenses including
depreciation expense associated with the scrubber will also be recovered through
a rider mechanism.
Once the
SO2 scrubber is
operational, SIGECO’s coal fired generating fleet will be 100 percent scrubbed
for SO2 and 90 percent
controlled for NOx, and mercury emissions will be reduced to meet the CAMR
mercury reduction standards described in the original 2005 emission reduction
regulations. The use of SCR technology positions the Company to be in
compliance with the CAIR deadlines specifying reductions in NOx emissions by
2009 and further reductions by 2015. SIGECO's investments in
scrubber, SCR and fabric filter technology positions it to comply with more
stringent mercury reduction requirements should CAMR regulations be further
modified.
If
legislation requiring reductions in carbon dioxide and other greenhouse gases or
mandating energy from renewable sources is adopted, such regulation could
substantially affect both the costs and operating characteristics of the
Company’s fossil fuel generating plants and nonutility coal mining
operations. At this time and in the absence of final legislation,
compliance costs and other effects associated with reductions in greenhouse gas
emissions or obtaining renewable energy sources remain
uncertain.
SIGECO is
studying renewable energy alternatives, and on April 9, 2007, filed a green
power rider in order to allow customers to purchase green power and to obtain
approval of a contract to purchase 30 MW of power generated by wind
energy. The wind contract has been approved. Future
filings with the IURC with regard to new generation and/or further environmental
compliance plans will include evaluation of potential carbon
requirements.
Environmental Remediation
Efforts
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
contaminants 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. Indiana Gas submitted the remainder 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.
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 $21 million.
The
estimated accrued costs are limited to Indiana Gas’ 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 percent and 50
percent. With respect to insurance coverage, Indiana Gas has received
and recorded settlements from all known insurance carriers under insurance
policies in effect when these plants were in operation in an aggregate amount
approximating $20 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 October 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 in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has 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 and/or related to the site subject to the May 2007
lawsuit. 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 $8
million. With respect to insurance coverage, SIGECO has received and
recorded settlements from insurance carriers under insurance policies in effect
when these sites were in operation in an aggregate amount approximating the
costs it expects to incur.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites 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 and those costs
may not be subject to PRP or insurance recovery.
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 could be requested by the USEPA at some
future date.
|
14.
|
Rate & Regulatory
Matters
|
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
its Vectren North gas rate case. The order provided for a base rate
increase of $16.3 million and an ROE of 10.2 percent, with an overall rate of
return of 7.8 percent on rate base of approximately $793 million. The
settlement also provides for the recovery of $10.6 million of costs through
separate cost recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $20 million
and the treatment cannot extend beyond four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity
expense.
Vectren South (SIGECO) Gas
Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved its Vectren
South electric rate case. The settlement agreement provides for an
approximate $60.8 million electric rate increase to cover the Company’s cost of
system growth, maintenance, safety and reliability. The settlement
provides for, among other things: recovery of ongoing costs and deferred costs
associated with the MISO; operations and maintenance (O&M) expense increases
related to managing the aging workforce, including the development of expanded
apprenticeship programs and the creation of defined training programs to ensure
proper knowledge transfer, safety and system stability; increased O&M
expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by Vectren’s sharing equally with
customers any profit earned above or below $10.5 million of wholesale power
margin; recovery of and return on the investment in past demand side management
programs to help encourage conservation during peak load periods; timely
recovery of the Company’s investment in certain new electric transmission
projects that benefit the MISO infrastructure; an overall rate of return of 7.32
percent on rate base of approximately $1,044 million and an allowed return on
equity (ROE) of 10.4 percent.
Vectren South (SIGECO) Gas
Base Rate Order Received
On August
1, 2007, the Company received an order from the IURC which approved its Vectren
South gas rate case. The order provided for a base rate increase of $5.1
million and an ROE of 10.15 percent, with an overall rate of return of 7.20
percent on rate base of approximately $122 million. The settlement
also provides for the recovery of $2.6 million of costs through separate cost
recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $3 million
and the treatment cannot extend beyond three years on each project.
With this
order, the company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity
expense.
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Case Filing
In
November 2007, the Company filed with the PUCO a request for an increase in its
base rates and charges for VEDO’s distribution business in its 17-county service
area in west central Ohio. The filing indicates that an increase in
base rates of approximately $27 million is necessary to cover the ongoing cost
of operating, maintaining and expanding the approximately 5,200-mile
distribution system used to serve 318,000 customers.
In
addition, the Company is seeking to increase the level of the monthly service
charge as well as extending the lost margin recovery mechanism currently in
place to be able to encourage customer conservation and is also seeking approval
of expanded conservation-oriented programs, such as rebate offerings on
high-efficiency natural gas appliances for existing and new home construction,
to help customers lower their natural gas bills. The Company is also
seeking approval of a multi-year bare steel and cast iron capital replacement
program.
The
Company anticipates an order from the PUCO in late 2008.
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 proposed 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. These mechanisms are 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 that provides for a
five-year energy efficiency program. It allows the Company’s Indiana
utilities to recover a majority of the costs of promoting the conservation of
natural gas through conservation trackers that work in tandem with a lost margin
recovery mechanism. The order was implemented in the North service
territory in December 2006, and provides for recovery of 85 percent of the
difference between weather normalized revenues actually collected by the Company
and the revenues approved in the Company’s most recent rate
case. Energy efficiency programs began in the North gas territory in
December 2006. A similar approach regarding lost margin recovery
commenced in the South gas territory on August 1, 2007, as the new base rates
went into effect, allowing for recovery of 100 percent of the difference between
weather normalized revenues collected and the revenues approved in that rate
case. The recent Vectren North base rate order also allows for full
recovery of the difference between weather normalized revenues collected by the
Company and the revenues provided for in that settlement, superseding the
original December 2006 order. While most expenses associated with
these programs are recoverable, in the first program year the Company incurred
$0.9 million in program costs without recovery, of which $0.8 million was
expensed in 2007 and, in addition contributed $0.2 million in assets that are
being depreciated over the term of the program without
recovery.
Ohio
In June
2007, the Public Utilities Commission of Ohio (PUCO) approved a settlement that
provides for the implementation of a lost margin recovery mechanism and a
related conservation program for the Company’s Ohio operations. This
order confirms the guidance the PUCO previously provided in a September 2006
decision. The conservation program, as outlined in the September 2006
PUCO order and as affirmed in this order, provides for a two year, $2 million
total conservation program to be paid 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. Approximately 60 percent of the Company’s Ohio customers are
eligible for the conservation programs. The Ohio Consumer Counselor
(OCC) and another intervener requested a rehearing of the June 2007 order and
the PUCO granted that request in order to have additional time to consider the
merits of the request. In accordance with accounting authorization
previously provided by the PUCO, the Company began recognizing the impact of the
September 2006 order on October 1, 2006, and has recognized cumulative revenues
of $4.6 million, of which $3.3 million was recorded in 2007. The OCC
appealed the PUCO’s accounting authorization to the Ohio Supreme Court, but that
appeal has been dismissed as premature pending the PUCO’s consideration of
issues raised in the OCC’s request for rehearing. Since October 1,
2006, the Company has been ratably accruing its $2 million
commitment.
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.
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. The Company is typically in a net sales position with
MISO and is only occasionally in a net purchase position. Net positions
are determined on an hourly basis. When the Company is a net seller such
net revenues are included in Electric Utility revenues and when the
Company is a net purchaser such net purchases are included in Cost of fuel and purchased power. The Company also
receives transmission revenue that results from other members’ use of the
Company’s transmission system. These revenues are also included in
Electric Utility
revenues.
Pursuant
to an order from the IURC received in December 2001, certain MISO startup costs
(referred to as Day 1 costs) were deferred, and those deferred costs are now
being recovered through base rates that went into effect on August 15,
2007. On June 1, 2005, Vectren, together with three other Indiana
electric utilities, received regulatory authority from the IURC to recover fuel
related costs and to defer 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. During
2006, the IURC reaffirmed the definition of certain costs as fuel related; the
Company is following those guidelines. Other MISO fuel related and
non-fuel related administrative costs were deferred, and those deferred costs
are now being recovered through base rates that went into effect on August 15,
2007. The IURC order authorizing new base rates also provides for a
tracking mechanism associated with ongoing MISO-related costs and transmission
revenues.
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 a pending Day 3 market, where MISO plans to
provide bid-based regulation and contingency operating reserve markets, it is
difficult to predict near term operational impacts. MISO has
indicated that the Day 3 ancillary services market would begin in June
2008.
The 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 is expected to be significant. The Company will timely
recover its investment in certain new electric transmission projects that
benefit the MISO infrastructure at a FERC approved rate of return.
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 percent 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 is 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. SIGECO’s portion of its commitment ceased in August 2007, and
Indiana Gas’ portion of the commitment ceased on February 14, 2008.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
VEDO Base Rate Increase in
2005
On April
13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas
distribution business. The base rate change was implemented on April
14, 2005 and provide for the recovery of some level of on-going costs to comply
with the Pipeline Safety Improvement Act of 2002.
Gas Cost Recovery (GCR)
Audit Proceedings
In 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 October 2002 and in
2006, an additional $0.8 million was disallowed related to the audit period
ending October 2005. The initial audit period provided the PUCO staff its
initial review of the portfolio administration arrangement between VEDO and
ProLiance. Since November 1, 2005, the Company has used a provider other
than ProLiance for these services.
Through a
series of rehearings and appeals, including action by the Ohio Supreme Court in
the first quarter of 2007, the Company was required to refund $8.6 million to
customers. In total, the Company has reflected $6.2 million in Cost of gas sold related to
this matter, of which $1.1 million, $4.1 million, and $1.0 million were recorded
in 2007, 2005, and 2003, respectively. The impact of the disallowance
includes a sharing of the ordered refund by Vectren’s partner in
ProLiance. As of December 31, 2007, all amounts have been refunded to
customers.
|
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. Contracts with counter-parties subject to master netting
arrangements are presented net in the Consolidated Balance
Sheets. 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. Ineffective portions of
hedging arrangements are marked-to-market through earnings. For fair
value hedges, both the derivative and the underlying are 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 risk management, SO2 emission allowance
risk management, natural gas procurement, and interest rate risk
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. Asset
optimization contracts that are derivatives are recorded at market
value.
At
December 31, 2007 and 2006, no asset optimization derivative contracts were
outstanding. 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 $39.8 million in 2007, $29.8
million in 2006 and $38.0 million in 2005.
Synfuel Risk
Management
As
discussed in Note 3, the Company’s synfuel operations were exposed to commodity
price risk associated with oil. The Company executed derivative
instruments designed to limit the effects of a phase out of synfuel tax credits
and other risks. During 2006 the Company purchased contracts with a
notional amount of 0.5 million barrels to mitigate 2006 risks. 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 and other risks. The mark to
market loss associated with these contracts totaled $2.5 million in 2006 and was
also reflected in Other-net. In
2007, these contracts increased income $13.4 million, all of which was a
realized gain. The fair value of those contracts, which was recorded
in Prepayments and other current
assets, totaled
$22.8 million and $11.2 million as of December 31, 2007 and 2006,
respectively. The pretax impact of an insurance contract related to
synfuels was a loss of $0.3 million in 2007, 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, the fair value of the insurance contract, which is
included in Prepayments and other current
assets, totaled
$4.4 million and was received in 2007.
SO2 Emission Allowance
Risk Management
The
Company’s wholesale power marketing operations are exposed to price risk
associated with SO2 emission
allowances. To mitigate this risk, the Company executed call options
to hedge wholesale emission allowance utilization in future
periods. The Company designated and documented these derivatives as
cash flow hedges. At December 31, 2007, a deferred gain of
approximately $0.7 million remains in accumulated comprehensive income related
to these call options 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, 2007.
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 may mitigate these risks by using derivative
contracts. 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, 2007 and 2006, 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.
Interest
rate swaps hedging the fair value of a planned VUHI debt issuance in 2008 with a
total notional amount of $80.0 million are outstanding. The fair
value liability associated with those swaps was $8.9 million at December 31,
2007. At December 31, 2006, interest rate swaps hedging the fair
value of fixed-rate debt with a total notional amount of $17.5 million were
outstanding, and the fair value liability associated with those swaps was $0.3
million. Related to derivative instruments associated with completed
debts issuances, an approximate $2.2 million net regulatory liability remains at
December 31, 2007. Of that net liability, $0.6 million will be
reclassified to earnings in 2008, $0.6 million was reclassified to earnings in
2007, and $0.7 million was reclassified to earnings during
2006.
Fair Value of Other
Financial Instruments
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
||||||||||||||||
|
2007
|
2006
|
|||||||||||||||
|
(In
millions)
|
Carrying
Amount
|
Est.
Fair Value
|
Carrying
Amount
|
Est.
Fair Value
|
||||||||||||
|
Long-term
debt
|
$ |
1,249.0
|
$ |
1,236.6
|
$ |
1,256.3
|
$ |
1,276.2
|
||||||||
|
Short-term
borrowings & notes payable
|
557.0
|
557.0
|
464.8
|
464.8
|
||||||||||||
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, 2007 and 2006, 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 wholesale marketing
operations. The Company 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 asset optimization 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
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. The Nonutility Group includes all
amounts reported in Equity in earnings of unconsolidated
affiliates disclosed on the statement of operations and all investments
disclosed on the Statement of Cash Flows. For the periods presented,
all earnings from and investments in equity method investees are in the
Nonutility Group operating segment.
Corporate
and Other includes unallocated corporate expenses such as advertising 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)
|
2007
|
2006
|
2005
|
|||||||||
|
Revenues
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ |
1,269.4
|
$ |
1,232.5
|
$ |
1,359.7
|
||||||
|
Electric
Utility Services
|
487.9
|
422.2
|
421.4
|
|||||||||
|
Other
Operations
|
40.4
|
36.6
|
36.1
|
|||||||||
|
Eliminations
|
(38.7 | ) | (34.8 | ) | (35.4 | ) | ||||||
|
Total
Utility Group
|
1,759.0
|
1,656.5
|
1,781.8
|
|||||||||
|
Nonutility
Group
|
643.4
|
503.2
|
344.3
|
|||||||||
|
Eliminations
|
(120.5 | ) | (118.1 | ) | (98.1 | ) | ||||||
|
Consolidated
Revenues
|
$ |
2,281.9
|
$ |
2,041.6
|
$ |
2,028.0
|
||||||
|
Profitability Measures - Net
Income
|
||||||||||||
|
Gas
Utility Services
|
$ |
41.7
|
$ |
41.5
|
$ |
34.7
|
||||||
|
Electric
Utility Services
|
52.6
|
41.6
|
50.4
|
|||||||||
|
Other
Operations
|
12.2
|
8.3
|
10.0
|
|||||||||
|
Utility
Group Net Income
|
106.5
|
91.4
|
95.1
|
|||||||||
|
Nonutility
Group Net Income
|
37.0
|
18.1
|
48.2
|
|||||||||
|
Corporate
& Other Net Loss
|
(0.4 | ) | (0.7 | ) | (6.5 | ) | ||||||
|
Consolidated
Net Income
|
$ |
143.1
|
$ |
108.8
|
$ |
136.8
|
||||||
|
Amounts Included in
Profitability Measures
|
||||||||||||
|
Depreciation & Amortization
|
||||||||||||
|
Utility Group
|
||||||||||||
|
Gas Utility Services
|
$ |
70.6
|
$ |
67.6
|
$ |
64.9
|
||||||
|
Electric Utility Services
|
66.0
|
61.8
|
56.9
|
|||||||||
|
Other
Operations
|
21.8
|
21.9
|
19.5
|
|||||||||
|
Total
Utility Group
|
158.4
|
151.3
|
141.3
|
|||||||||
|
Nonutility
Group
|
26.4
|
21.0
|
16.0
|
|||||||||
|
Corporate & Other
|
-
|
-
|
0.9
|
|||||||||
|
Consolidated
Depreciation & Amortization
|
$ |
184.8
|
$ |
172.3
|
$ |
158.2
|
||||||
|
Interest
Expense
|
||||||||||||
|
Utility Group
|
||||||||||||
|
Gas Utility Services
|
$ |
39.8
|
$ |
40.7
|
$ |
40.2
|
||||||
|
Electric Utility Services
|
29.6
|
28.6
|
23.7
|
|||||||||
|
Other Operations
|
11.2
|
8.2
|
6.0
|
|||||||||
|
Total
Utility Group
|
80.6
|
77.5
|
69.9
|
|||||||||
|
Nonutility Group
|
21.9
|
20.0
|
14.6
|
|||||||||
|
Corporate & Other
|
(1.5 | ) | (1.9 | ) | (0.6 | ) | ||||||
|
Consolidated Interest Expense
|
$ |
101.0
|
$ |
95.6
|
83.9
|
|||||||
|
|
Year
Ended December 31,
|
|||||||||
|
(In
millions)
|
2007
|
2006 |
2005
|
|||||||
| Income Taxes | ||||||||||
| Utility Group | ||||||||||
|
Gas
Utility Services
|
$ 33.2
|
$ 22.6
|
$ 22.3
|
|||||||
|
Electric
Utility Services
|
38.0
|
25.3
|
33.5
|
|||||||
|
Other
Operations
|
(4.5)
|
(0.2)
|
1.7
|
|||||||
|
Total
Utility Group
|
66.7
|
47.7
|
57.5
|
|||||||
|
Nonutility
Group
|
10.5
|
(17.6)
|
(9.9)
|
|||||||
|
Corporate
& Other
|
(1.2)
|
0.2
|
(3.5)
|
|||||||
|
Consolidated
Income Taxes
|
$ 76.0
|
$ 30.3
|
$ 44.1
|
|||||||
|
Capital
Expenditures
|
||||||||||
|
Utility
Group
|
||||||||||
|
Gas
Utility Services
|
$ 128.9
|
$ 76.8
|
$ 81.0
|
|||||||
|
Electric
Utility Services
|
134.7
|
156.8
|
100.0
|
|||||||
|
Other
Operations
|
36.4
|
24.8
|
29.9
|
|||||||
|
Non-cash
costs & changes in accruals
|
(0.2)
|
(11.8)
|
3.6
|
|||||||
|
Total
Utility Group
|
299.8
|
246.6
|
214.5
|
|||||||
|
Nonutility
Group
|
34.7
|
34.8
|
17.1
|
|||||||
|
Consolidated
Capital Expenditures
|
$ 334.5
|
$ 281.4
|
$ 231.6
|
|||||||
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Assets
|
||||||||
|
Utility
Group
|
||||||||
|
Gas
Utility Services
|
$ | 2,287.4 | $ | 1,953.6 | ||||
|
Electric
Utility Services
|
1,369.2 | 1,277.6 | ||||||
|
Other
Operations
|
2,229.7 | 225.9 | ||||||
|
Eliminations
|
(2,242.6 | ) | (16.3 | ) | ||||
|
Total
Utility Group
|
3,643.7 | 3,440.8 | ||||||
|
Nonutility
Group
|
704.1 | 639.7 | ||||||
|
Corporate
& Other
|
407.0 | 466.7 | ||||||
|
Eliminations
|
(458.3 | ) | (455.6 | ) | ||||
|
Consolidated
Assets
|
$ | 4,296.4 | $ | 4,091.6 | ||||
|
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)
|
2007
|
2006
|
||||||
|
Prepaid
gas delivery service
|
$ |
65.2
|
$ |
66.2
|
||||
|
Deferred
income taxes
|
29.9
|
3.6
|
||||||
|
Synfuels
related derivatives
|
22.8
|
15.6
|
||||||
|
Prepaid
taxes
|
9.8
|
12.3
|
||||||
|
Utilicom
receivable - current
|
-
|
44.6
|
||||||
|
Other
prepayments & current assets
|
32.8
|
30.4
|
||||||
|
Total prepayments & other
current assets
|
$ |
160.5
|
$ |
172.7
|
||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Refunds
to customers & customer deposits
|
$ |
43.7
|
$ |
43.0
|
||||
|
Accrued
taxes
|
34.2
|
31.6
|
||||||
|
Accrued
interest
|
17.4
|
16.8
|
||||||
|
Asset
retirement obligation
|
9.5
|
-
|
||||||
|
Accrued
salaries & other
|
67.0
|
55.8
|
||||||
|
Total accrued
liabilities
|
$ |
171.8
|
$ |
147.2
|
||||
Equity in earnings of unconsolidated
affiliates in the Consolidated Statements of Income consists of the
following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
ProLiance Holdings
, LLC
|
$ |
41.0
|
$ |
35.3
|
$ |
52.4
|
||||||
|
Haddinton
Energy Partners, LP
|
(0.2 | ) |
0.3
|
7.7
|
||||||||
|
Pace
Carbon Synfuels, LP
|
(20.0 | ) | (17.8 | ) | (15.7 | ) | ||||||
|
Other
|
2.1
|
(0.8 | ) |
1.2
|
||||||||
|
Total equity in earnings of
unconsolidated affiliates
|
$ |
22.9
|
$ |
17.0
|
$ |
45.6
|
||||||
Other – net in the Consolidated Statements of Income consists of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
AFUDC
& capitalized interest
|
$ |
6.3
|
$ |
5.3
|
$ |
2.5
|
||||||
|
Interest
income
|
2.9
|
4.0
|
3.8
|
|||||||||
|
Synfuel-related
activity
|
23.4
|
(11.4 | ) | (1.9 | ) | |||||||
|
Broadband
charges
|
0.1
|
(1.9 | ) | (1.1 | ) | |||||||
|
All
other income
|
4.1
|
1.3
|
2.9
|
|||||||||
|
Total other –
net
|
$ |
36.8
|
$ | (2.7 | ) | $ |
6.2
|
|||||
|
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
|
||||||||||||
|
2007
|
||||||||||||||||
|
Operating
revenues
|
$ |
834.0
|
$ |
421.7
|
$ |
381.4
|
$ |
644.8
|
||||||||
|
Operating
income
|
95.6
|
39.7
|
45.1
|
80.1
|
||||||||||||
|
Net
income
|
70.1
|
16.0
|
17.1
|
39.9
|
||||||||||||
|
Earnings
per share:
|
||||||||||||||||
|
Basic
|
$ |
0.92
|
$ |
0.21
|
$ |
0.23
|
$ |
0.53
|
||||||||
|
Diluted
|
0.92
|
0.21
|
0.22
|
0.52
|
||||||||||||
|
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
|
||||||||||||
|
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. However, in December 2007, the FASB issued
proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). This proposed FSP partially defers the
effective date of Statement 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of this FSP. The Company will adopt SFAS 157 on January 1, 2008,
except as it applies to those nonfinancial assets and nonfinancial liabilities
as noted in proposed FSP FAS 157-b. The partial adoption of SFAS 157
will not have a material impact on the Company’s financial position, results of
operations or cash flows.
SFAS
159
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities – Including an Amendment of FASB Statement No.
115 (SFAS 159). SFAS 159 permits entities to measure many financial
instruments and certain other items at fair value. Items eligible for
the fair value measurement option include: financial assets and financial
liabilities with certain exceptions; firm commitments that would otherwise not
be recognized at inception and that involve only financial instruments;
nonfinancial insurance contracts and warranties that the insurer can settle by
paying a third party to provide those goods or services; and host financial
instruments resulting from separation of an embedded financial derivative
instrument from a nonfinancial hybrid instrument. The fair value
option may be applied instrument by instrument, with few exceptions, is an
irrevocable election and is applied only to entire instruments. SFAS
159 is effective as of the beginning of an entity’s first fiscal year that
begins after November 15, 2007. The Company will adopt SFAS 159 on
January 1, 2008, and does not expect that adoption will have a material impact
on its financial statements and results of operations.
SFAS 141 (Revised
2007)
In
December 2007, the FASB issued SFAS 141, Business Combinations (SFAS
141). SFAS 141 establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any Noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141 applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. SFAS 141 applies prospectively to
business combinations with an acquisition date on or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. Early adoption is not permitted. The Company will adopt
SFAS 141 on January 1, 2009, and because the provisions of this standard are
applied prospectively, the impact to the Company cannot be determined until the
transactions occur.
SFAS
160
In
December 2007, the FASB issued SFAS 160, Noncontrolling Interests in
Consolidated Financial Statements-an Amendment of ARB No. 51 (SFAS
160). SFAS 160 establishes accounting and reporting standards that
require that the ownership percentages in subsidiaries held by parties other
than the parent be clearly identified, labeled, and presented separately from
the parent’s equity in the equity section of the consolidated balance sheet; the
amount of consolidated net income attributable to the parent and the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement; that changes in the parents ownership
interest while it retains control over its subsidiary be accounted for
consistently; that when a subsidiary is deconsolidated, any retained
noncontrolling equity investment be initially measured at fair value; and that
sufficient disclosure is made to clearly identify and distinguish between the
interests of the parent and the noncontrolling owners. SFAS 160
applies to all entities that prepare consolidated financial statements, except
for non-profit entities. SFAS 160 is effective for fiscal years
beginning after December 31, 2008. Early adoption is not
permitted. The Company will adopt SFAS 160 on January 1, 2009, and is
currently assessing the impact this statement will have on its financial
statements and results of operations.
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, 2007, 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, 2007, 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,
2007, to ensure that information required to be disclosed in reports filed or
submitted under the Exchange Act is:
|
1)
|
recorded,
processed, summarized and reported within the time periods specified in
the SEC’s rules and forms, and
|
|
|
2)
|
accumulated
and communicated to management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
|
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, 2007.
The
effectiveness of internal control over financial reporting as of December 31,
2007, 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 Proxy
Statement for its 2008 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 the address listed above.
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 Proxy Statement for
its 2008 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 Proxy Statement for its 2008 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, 2007, 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
|
1,432,774
|
(1)
|
$ 23.88
|
(1)
|
2,768,528
|
(2)
|
||||
|
|
||||||||||
|
Equity
compensation plans not approved by security holders
|
-
|
-
|
-
|
|||||||
|
Total
|
1,432,774
|
$ 23.88
|
2,768,528
|
|||||||
|
(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 21,170 restricted shares and
155,400 restricted stock units approved by the board of directors’
Compensation Committee, effective January 1,
2008.
|
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 Proxy Statement for
its 2008 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 Proxy Statement for
its 2008 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 Holdings, LLC are attached as exhibit 99.1 to this Form
10-K.
Supplemental
Schedules
For the
years ended December 31, 2007, 2006, and 2005, 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
2007 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ |
3.3
|
$ |
16.6
|
$ |
-
|
$ |
16.2
|
$ |
3.7
|
||||||||||
|
Year
2006 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ |
2.8
|
$ |
15.3
|
$ |
-
|
$ |
14.8
|
$ |
3.3
|
||||||||||
|
Year
2005 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ |
2.0
|
$ |
15.1
|
$ |
-
|
$ |
14.3
|
$ |
2.8
|
||||||||||
|
OTHER
RESERVES:
|
||||||||||||||||||||
|
Year
2007 – Restructuring costs
|
$ |
1.7
|
$ |
-
|
$ |
-
|
$ |
1.1
|
$ |
0.6
|
||||||||||
|
Year
2006 – Restructuring costs
|
$ |
2.4
|
$ |
-
|
$ |
-
|
$ |
0.7
|
$ |
1.7
|
||||||||||
|
Year
2005 – Restructuring costs
|
$ |
2.7
|
$ |
-
|
$ |
-
|
$ |
0.3
|
$ |
2.4
|
||||||||||
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 99.
Vectren
Corporation
Form 10-K
Attached Exhibits
The
following Exhibits are included in this Annual Report on Form 10-K.
|
Exhibit
Number
|
Document
|
|
|
|
The
following Exhibits, as well as the Exhibits listed above, were filed
electronically with the SEC with this filing.
|
Exhibit
Number
|
Document
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 and designated in Form 10-K for
the year ended December 31, 2004, File No. 1-15467, as Exhibit
4.1.) October 1, 2004. (Filed and designated in Form
10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit
4.2.) April 1, 2005 (Filed and designated in Form 10-K for the
year ended December 31, 2007, File No 1-15467, as Exhibit
4.1) March 1, 2006 (Filed and designated in Form 10-K for the
year ended December 31, 2007, File No 1-15467, as Exhibit
4.2) December 1, 2007 (Filed and designated in Form 10-K for
the year ended December 31, 2007, File No 1-15467, as Exhibit
4.3)
|
|
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 restricted stock grant
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.1.)
|
|
10.10
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock units
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.2.)
|
|
10.11
|
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.)
|
|
10.12
|
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.)
|
|
10.13
|
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.)
|
|
10.14
|
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.)
|
|
10.15
|
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.)
|
|
10.16
|
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.)
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|
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. (Filed
herewith.)
23. Consents of Experts and
Counsel
The consents of Deloitte & Touche LLP are attached hereto as Exhibits 23.1
and 23.2. (Filed herewith.)
|
|
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 (Filed
herewith.)
|
|
|
Chief
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed
herewith.)
|
|
|
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 (Filed herewith.)
|
|
99.1 ProLiance Holdings, LLC
Consolidated Financial Statements for the Fiscal Years Ended September 30,
2007, 2006, and 2005. (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 19,
2008 /s/ Niel C.
Ellerbrook
Niel C.
Ellerbrook,
Chairman,
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,
Chief Executive Officer, and Director
|
February
19, 2008
|
||
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Niel
C. Ellerbrook
|
(Principal
Executive Officer)
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|||
|
/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President and Chief Financial Officer
|
February
19, 2008
|
||
|
Jerome
A. Benkert, Jr.
|
(Principal
Financial Officer)
|
|||
|
/s/ M.
Susan Hardwick
|
Vice
President, Controller and Assistant Treasurer
|
February
19, 2008
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
|
/s/
John M. Dunn
|
Director
|
February
19, 2008
|
||
|
John
M. Dunn
|
||||
|
/s/
John D. Engelbrecht
|
Director
|
February
19, 2008
|
||
|
John
D. Engelbrecht
|
||||
|
/s/
Anton H. George
|
Director
|
February
19, 2008
|
||
|
Anton
H. George
|
||||
|
/s/
Martin C. Jischke
|
Director
|
February
19, 2008
|
||
|
Martin
J. Jischke
|
||||
|
/s/
Robert L. Koch II
|
Director
|
February
19, 2008
|
||
|
Robert
L. Koch II
|
||||
|
/s/
William G Mays
|
Director
|
February
19, 2008
|
||
|
William
G. Mays
|
-102-
|
|||
|
/s/
J. Timothy McGinley
|
Director
|
February
19, 2008
|
||
|
J.
Timothy McGinley
|
||||
|
/s/
Richard P. Rechter
|
Director
|
February
19, 2008
|
||
|
Richard
P. Rechter
|
||||
|
/s/
R. Daniel Sadlier
|
Director
|
February
19, 2008
|
||
|
R.
Daniel Sadlier
|
|
|||
|
/s/
Richard W. Shymanski
|
Director
|
February
19, 2008
|
||
|
Richard
W. Shymanski
|
||||
|
/s/
Michael L Smith
|
Director
|
February
19, 2008
|
||
|
Michael
L Smith
|
||||
|
/s/
Jean L. Wojtowicz
|
Director
|
February
19, 2008
|
||
|
Jean
L. Wojtowicz
|