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, 2008
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. □
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, 2008, was $2,512,375,819.
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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81,024,979
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January 31, 2009
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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 2009 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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OCC: Ohio
Office of the Consumer Counselor
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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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MISO:
Midwest Independent System Operator
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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 as
soon as reasonably practicable after electronically filing or furnishing the
reports to the SEC, 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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Part
IV
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107
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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 111,000
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 317,000 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 legacy businesses that
have invested in energy-related opportunities and services, real estate, and
leveraged leases, among other investments. 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, and infrastructure
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, 2008, the
Company had $4.6 billion in total assets, with $3.8 billion (83 percent)
attributed to the Utility Group and $0.8 billion (17 percent) attributed to the
Nonutility Group. Net income for the year ended December 31, 2008,
was $129.0 million, or $1.65 per share of common stock, with net income of
$111.1 million attributed to the Utility Group and $18.9 million attributed to
the Nonutility Group, and a net loss of $1.0 million 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. For further information
regarding the activities and assets of operating segments within these Groups,
refer to Note 18 in the Company’s Consolidated Financial Statements included
under “Item 8 Financial Statements and Supplementary Data.”
Following
is a more detailed description of the Utility Group and Nonutility
Group. Corporate and Other operations are not
significant.
Utility
Group
The
Utility Group is comprised of Utility Holdings’ operations. The
operations of the Utility Group consist of the Company’s regulated operations
and other operations that provide information technology and other support
services to those regulated operations. The Company segregates its
regulated operations into a Gas Utility Services operating segment and an
Electric Utility Services operating segment. The Gas Utility Services
segment includes the operations of Indiana Gas, the Ohio operations, and
SIGECO’s natural gas distribution business and provides natural gas distribution
and transportation services to nearly two-thirds of Indiana and to west central
Ohio. The Electric Utility Services segment includes the operations
of SIGECO’s electric transmission and distribution services, which provides
electric distribution services primarily to southwestern Indiana, and the
Company’s power generating and wholesale power 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, 2008, the Company supplied natural gas service to approximately
996,300 Indiana and Ohio customers, including 910,000 residential, 84,700
commercial, and 1,600 industrial and other contract
customers. Average gas utility customers served were approximately
986,700 in both 2008 and 2007; and 981,300 in 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, ethanol 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, 2008, gas utility revenues were approximately $1,432.7
million, of which residential customers accounted for 67 percent and commercial
27 percent. Industrial and other contract customers account for the remaining 6
percent of revenues due to the high number of transportation customers in that
customer class.
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 delivered to both sales and
transportation customers (throughput) were 206.3 MMDth for the year ended
December 31, 2008. Gas sold and transported to residential and
commercial customers was 114.8 MMDth representing 56 percent of
throughput. Gas transported or sold to industrial and other contract
customers was 91.5 MMDth representing 44 percent of throughput. Rates
for transporting gas generally provide for the same margins earned by selling
gas under applicable sales tariffs.
Availability of Natural
Gas
The
volume of gas sold is seasonal and affected by variations in weather
conditions. To mitigate seasonal demand, the Company’s Indiana gas
utilities have storage capacity at seven active underground gas storage fields
and six liquefied petroleum air-gas manufacturing
plants. 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
volumes of gas per day that can be delivered during peak demand periods for each
utility are located in “Item 2 Properties.”
Natural
Gas Purchasing Activity in Indiana
The
Indiana utilities also contract with its affiliate, ProLiance Holdings, LLC
(ProLiance), to ensure availability of gas. ProLiance is an
unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens
Energy Group (Citizens). (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). The Company also prepays
ProLiance for natural gas delivery services during the seven months prior to the
peak heating season in lieu of maintaining gas storage. 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.
Natural
Gas Purchasing Activity in Ohio
As a
result of a June 2005 PUCO order, the Company established an annual bidding
process for VEDO’s gas supply and portfolio administration
services. From November 1, 2005 through September 30, 2008, the
Company used a third party provider for these services. Prior to
October 31, 2005, ProLiance also supplied natural gas to Utility Holdings’ Ohio
operations.
On April
30, 2008, the PUCO issued an Order adopting a stipulation involving the Company,
the OCC and other interveners. The order involved the first
two stages of a three stage plan to exit the merchant function in the
Company’s Ohio service territory.
Stage one
of the plan was implemented on October 1, 2008 and continues through March 31,
2010. As part of stage one, wholesale suppliers that were winning bidders
in a PUCO approved auction provide the gas commodity to VEDO for resale to its
customers at auction-determined standard pricing. This standard
pricing is comprised of the monthly NYMEX settlement price plus a fixed
adder. On October 1, 2008, the Company transferred its natural gas
inventory at book value to the winning bidders, receiving proceeds of
approximately $107 million, and now purchases natural gas from those suppliers,
which include Vectren Source, a wholly owned subsidiary of Vectren, essentially
on demand. This method of purchasing gas eliminates the need for
monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits.
In the
second stage of this process, the Company will no longer sell natural gas
directly to customers; rather state- certified Competitive Retail Natural Gas
Suppliers, which are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers at auction-determined standard
pricing, and the Company will transport that gas supply to the customers.
In the third stage, which was not part of the April 2008 order, it is
contemplated that all of the Company’s Ohio customers will choose their
commodity supplier from state-certified Competitive Retail Natural Gas Suppliers
in a competitive market.
The PUCO
has also provided for an Exit Transition Cost rider for the first two stages of
the transition, which allows the Company to recover costs associated with the
transition, and it is anticipated this rider will remain effective for the
entire transition. Since the cost of gas is currently passed through
to customers through a PUCO approved recovery mechanism, the impact of exiting
the merchant function should not have a material impact on Company earnings or
financial condition.
Total
Natural Gas Purchased Volumes
In 2008,
Utility Holdings purchased 109,059 MDth volumes of gas at an average cost of
$9.61 per Dth, of which approximately 71 percent was purchased from ProLiance, 2
percent was purchased from Vectren Source, as discussed above, and 27 percent
was purchased from third party providers. The average cost of gas per
Dth purchased for the previous five years was $9.61 in 2008, $8.14 in 2007,
$8.64 in 2006, $9.05 in 2005, and $6.92 in 2004.
Electric
Utility Services
At
December 31, 2008, the Company supplied electric service to approximately
141,300 Indiana customers, including approximately 122,800 residential, 18,400
commercial, and 100 industrial and other customers. Average electric
utility customers served were approximately 141,100 in 2008; 140,800 in 2007;
and 139,700 in 2006.
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, ethanol and
coal mining.
Revenues
For the
year ended December 31, 2008, retail electricity sales totaled 5,323.4 GWh,
resulting in revenues of approximately $457.3 million. Residential
customers accounted for 37 percent of 2008 revenues; commercial 28 percent;
industrial 33 percent, and municipal and other 2 percent. In
addition, in 2008 the Company sold 1,512.9 GWh through wholesale activities in
2008 principally to the MISO. Wholesale revenues, including
transmission sales, totaled $66.9 million in 2008.
System
Load
Total
load for each of the years 2004 through 2008 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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7/21/2008
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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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Total
load at peak (1)
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1,242 | 1,341 | 1,325 | 1,315 | 1,222 | |||||||||||||||
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Generating
capability
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1,295 | 1,295 | 1,351 | 1,351 | 1,351 | |||||||||||||||
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Firm
purchase supply
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135 | 130 | 107 | 107 | 105 | |||||||||||||||
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Interruptible
contracts
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62 | 62 | 62 | 76 | 51 | |||||||||||||||
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Total
power supply capacity
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1,492 | 1,487 | 1,520 | 1,534 | 1,507 | |||||||||||||||
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Reserve
margin at peak
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20 | % | 11 | % | 15 | % | 17 | % | 23 | % | ||||||||||
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(1)
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The
total load at peak is increased 25 MW in 2007-2005 from the total load
actually experienced. The additional 25 MW represents load that
would have been incurred if the 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 2008 and 2004, the Summer Cycler
program was not activated.
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The
winter peak load for the 2007-2008 season of approximately 960 MW occurred on
January 25, 2008. The prior year winter peak load was approximately
961 MW, occurring on December 7, 2006.
Generating
Capability
Installed
generating capacity as of December 31, 2008, 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 2008 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
6,653 GWh in 2008. Further information about the Company’s owned
generation is included in Item 2 Properties.
There are
substantial coal reserves in the southern Indiana area, and coal for coal-fired
generating stations has been supplied from operators of nearby coal mines,
including coal mines in Indiana owned by Vectren Fuels, Inc., a wholly owned
subsidiary of the Company. Approximately 3.2 million tons were
purchased for generating electricity during 2008, of which approximately 91
percent was supplied by Vectren Fuels, Inc. from its mines and third party
purchases. The average cost of coal paid by the utility in generating
electric energy for the years 2004 through 2008 follows:
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Year
Ended December 31,
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Average
Delivered
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2008
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2007
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2006
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2005
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2004
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Cost per
Ton
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$ 42.50
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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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Cost per
MWh
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20.84
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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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On
January 1, 2009, SIGECO began purchasing coal from Vectren Fuels, Inc. (Fuels)
under new coal purchase agreements. The term of these coal purchase
agreements continues to December 31, 2014, with prices specified ranging from
two to four years. New pricing reflects current Illinois Basin market
prices and will result in substantially higher costs in 2009, compared to prior
years.
Firm Purchase
Supply
The
Company maintains a 1.5 percent interest in the Ohio Valley Electric Corporation
(OVEC). 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 OVEC makes available approximately 30 MW of capacity for use in
other operations. The Company purchased approximately 236 GWh from
OVEC in 2008.
The
Company has a capacity contract with Duke Energy Marketing America, LLC. 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 insignificant amounts under this contract
in 2008.
The
Company executed a capacity contract with Benton County Wind Farm, LLC on April
15, 2008 to purchase as much as 30 MW from a wind farm located in Benton County,
Indiana. The contract expires in 2029. At the time of peak
in 2008 approximately 5 MW was available. The Company purchased
approximately 59 GWh under this contract in 2008.
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 2008 totaled
80 GWh.
Midwest Independent System
Operator (MISO) Capacity Purchase
In May
2008, the Company executed a MISO capacity purchase from Sempra Energy Trading,
LLC to purchase 100MW of name plate capacity from its generating facility in
Dearborn, Michigan. The term of the contract begins January 1, 2010
and continues through December 31, 2012.
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 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 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 have considered 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, 2008, over
80,000 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 certain
industrial and commercial large volume customers to choose their commodity
supplier.
Regulatory
and Environmental Matters
See “Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s 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 Energy Group (Citizens), 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’ utilities. 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 2008.
For the
year ended December 31, 2008, ProLiance’s revenues, including sales to Vectren
companies, were $2.9 billion, compared to $2.3 billion in 2007 and $2.5 billion
in 2006. During the three years ended December 31, 2008, the pre-tax
earnings of ProLiance have exceeded 20 percent of Vectren’s pre-tax earnings in
certain annual periods. In accordance with Regulation S-X, paragraph
3-09, ProLiance’s audited financial statements as of and for its fiscal years
ending September 30, 2008, 2007, and 2006, 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 Northeast United States to over 170,000
residential and commercial customers. This customer base reflects
approximately 50,000 of VEDO’s customers that have voluntarily opted to choose
their natural gas supplier and the supply of natural gas to nearly 40,000
equivalent customers in VEDO’s service territory as part of VEDO’s process of
exiting the merchant function, which began October 1, 2008. Further,
the customer base also reflects a reduction due to exiting the Georgia market in
2008. Vectren Source generated approximately $182.6 million in
revenues for 2008 compared to $168.3 million in 2007 and $162.5 million in
2006. Gas sold approximated 16,210 MDth in 2008; 13,543 MDth in 2007;
and 12,228 MDth in 2006. Average customers served by Vectren Source
were 157,000 in 2008; 154,000 in 2007; and 144,000 in 2006.
Coal
Mining
The Coal
Mining group mines and sells coal to the Company’s utility operations and to
other third parties through its wholly owned subsidiary, Vectren Fuels, Inc
(Fuels). In 2008, the Company operated one underground mine
(Prosperity) and one surface mine (Cypress Creek). Both mines are
located in Indiana. All coal is high-to-mid sulfur bituminous coal
from the Illinois Basin. The Company engages contract mining
companies to perform substantially all mining operations.
Oaktown Mine
Expansion
In April
2006, Fuels announced plans to open two new underground
mines. Production is expected to begin in mid 2009, with the
second mine opening late the following year. Current reserves at the
two mines are estimated at 88 million tons. Once in full production,
the two new mines are expected to produce 5 million tons of coal per
year. Of the total $170 million expected investment, the Company has
invested $68 million, inclusive of $23 million in land and buildings, $38
million in mine development and equipment, and $7 million in advanced royalty
payments, through December 31, 2008.
The
Oaktown mine infrastructure is located on 1,100 acres near Oaktown in Knox
County, Indiana. Oaktown’s location is within 50 miles of multiple
coal-fired power plants including a coal gasification plant currently under
construction. It is estimated approximately 25,000 acres of coal will
be mined during the life of the mine. Access to the mine is planned
via a 90 foot deep box cut and a 2,200 foot slope on a 14 degree grade, reaching
coal in excess of 375 feet below the surface.
Oaktown
is a room and pillar underground mine meaning that main airways and
transportation entries are developed and maintained while remote-controlled
continuous miners extract coal from so-called rooms by removing coal from the
seam, leaving pillars to support the roof. Shuttle cars or similar
transportation is used to transport coal to a conveyor belt for transport to the
surface. There are two mines separated by a sandstone
channel. The seam thickness ranges from 4 feet to over 9
feet. The mine’s wash plant is sized to process 800 tons per hour
initially with a planned expansion to 1,600 tons per hour. The mine
will also be connected to a railway and equipped to handle 110 to 120 car unit
trains.
Prosperity
Mine
Prosperity
is an underground mine located on 1,100 surface acres outside of Petersburg in
Pike County, Indiana. Prosperity is also a room and pillar mine where
coal removal is accomplished with continuous mining machines. The
mine entrance slopes gradually for 500 ft on a 9 degree grade and is more than
250 feet below ground level. The coal seam varies in thickness from
4-1/2 to 8 feet. The mine has a wash plant sized to process 1,000
tons/hour. The mine is connected to a railway and can handle 110-120
car unit trains. Coal is also transported via truck to its customers,
which include Vectren’s power supply operations and other third party
utilities. The mine opened in 2001, and the total plant and
development costs to date are $152 million. Through December 31,
2008, approximately 4,000 acres of coal have been mined with approximately 6,000
acres remaining. Reserves at December 31, 2008 approximate 32 million tons, not
including possible nearby expansion opportunities. The remaining
unamortized plant balance as of December 31, 2008 approximates $75 million,
inclusive of $15 million of land and buildings and $61 million of mine
development and equipment. Reserves, absent expansion, are expected
to be completely accessed by 2019.
Cypress
Creek
Cypress
Creek is an above-ground, or surface mine, located on 155 acres about 4 miles
north of Boonville in Warrick County, Indiana. Cypress Creek is a
combination truck/shovel, dozer push and high wall mining operation, meaning
large shovels or front-end loaders remove earth and rock covering a coal seam
and loading equipment place the coal into trucks for transportation to a
blending and loading area. Cypress Creek’s coal, is sold as a raw
product after sizing and blending with coal. Because of the cost of
extensive digging, the coal mining limit is 125 to 135 feet deep. All
coal mined from Cypress Creek is transported via truck to Vectren’s power supply
operations. The mine opened in 1998 and the total plant and
development costs were $29 million. As of December 31, 2008,
remaining reserves approximate 500,000 tons, all of which is expected to be
accessed in 2009. The remaining unamortized plant balance as of
December 31, 2008 approximates $11 million, inclusive of $1 million of land and
buildings and $10 million in mine development and equipment.
Following
is summarized data regarding coal mining operations:
|
Cypress
|
Oaktown
|
Oaktown
|
||||||||||||||||||
|
Creek
|
Prosperity
|
Mine
1
|
Mine
2
|
Totals
|
||||||||||||||||
|
Type
of Mining
|
Surface
|
Underground
|
Underground
|
Underground
|
||||||||||||||||
|
Mining
Technology
|
Truck
& Shovel
|
Room
& Pillar
|
Room
& Pillar
|
Room
& Pillar
|
||||||||||||||||
|
Tons
Mined (in thousands)
|
||||||||||||||||||||
|
2008
|
1,150 | 2,378 | - | - | 3,528 | |||||||||||||||
|
2007
|
1,433 | 2,632 | - | - | 4,065 | |||||||||||||||
|
2006
|
1,212 | 2,790 | - | - | 4,002 | |||||||||||||||
|
County
Located in Indiana
|
Warrick
|
Pike
|
Knox
|
Knox
|
||||||||||||||||
|
Coal
Reserves (thousands of tons)
|
500 | 32,000 | 50,000 | 38,000 | 120,500 | |||||||||||||||
|
Average
Heat Content (BTU/lb.)
|
10,500 | 11,300 | 11,100 | 11,300 | ||||||||||||||||
|
Average
Sulfur Content (lbs./ton)
|
8.0 | 4.0 | 5.6 | 4.8 | ||||||||||||||||
Energy Infrastructure Services
Energy
Infrastructure Services provides underground construction and repair to utility
infrastructure through Miller Pipeline Corporation (Miller) and energy
performance contracting and renewable energy services through Energy Systems
Group, LLC (ESG). Miller’s customers include Vectren’s
utilities.
Miller
Pipeline
Effective
July 1, 2006, the Company purchased the remaining 50 percent of Miller a
subsidiary of Duke Energy Corporation, 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 and renewable energy services 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.
Other
Businesses
The Other
Businesses group includes a variety of legacy, wholly owned operations and
investments that have invested in energy-related opportunities and services,
real estate, and leveraged leases, among other investments. Major
investments at December 31, 2008, 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. Partnership operations since
that date have been insignificant. 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, 2008, the Company and its consolidated subsidiaries had 3,700
employees, of which 1,600 are employees of Miller and 2,200 are subject to
collective bargaining arrangements.
Utility
Holdings
In
December 2008, the Company reached a three-year labor agreement, ending December
1, 2011 with Local 1393 of the International Brotherhood of Electrical Workers
and United Steelworkers of America Locals 12213 and 7441.
In July
2007, the Company reached a three-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2010.
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.
Miller
Pipeline
In 2008,
the International Union of Operating Engineers reached an agreement with the
Distribution Contractors Association. The Company, through its wholly
owned subsidiary, Miller, continues to honor national agreements negotiated by
the Distribution Contractors Association.
During
2006, Miller entered into several distributing and operating agreements with a
variety of construction unions including Laborers International Union of
America, the Teamsters, and the United Association of Journeymen and Apprentices
of the Plumbing and Pipe Fitting Industry. Miller negotiated these
agreements through the Distribution and Contractors Association and the Pipeline
Contractors Association. These agreements expire at various dates in
2009 through 2011. Agreements impacting Miller’s workforce expiring
in 2009 involve two local operator’s agreements and one local welder’s
agreement. No national agreements impacting Miller’s workforce expire
in 2009.
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.
Continued
deterioration in general economic conditions may have adverse
impacts.
The
current economic environment is challenging and uncertain. The
consequences of a prolonged recession may include a lower level of economic
activity and uncertainty regarding energy prices and the capital and commodity
markets. Further, the risks associated with industries in which the
Company operates and serves become more acute in periods of a slowing economy or
slow growth. Economic declines may be accompanied by a decrease in
demand for natural gas and electricity. The recent economic downturn
may have some negative impact on both gas and electric large
customers. This impact may include tempered growth, significant
conservation measures, and perhaps even plant closures or
bankruptcies. Deteriorating economic conditions may also lead to
lower residential and commercial customer counts and thus lower Company
revenues. It is also highly possible that a prolonged recession could
result in increased costs including pension costs, interest costs, and bad debt
expense in excess of historical levels.
Further,
the Company’s nonutility portfolio may also be negatively
impacted. Economic declines may be accompanied by a decrease in
demand for products and services offered by nonutility operations and therefore
lower revenues for those products and services. The recent economic
downturn may have some negative impact on utility industry spending for
construction projects, demand for coal, and spending on performance contracting
and renewable energy expansion. It is also possible that a prolonged
recession could result in further reductions in the value of certain nonutility
real estate and other legacy investments.
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,
ethanol and coal mining. While no one industrial customer comprises
10 percent of consolidated revenues, the top five industrial electric customers
comprise approximately 17 percent of electric utility revenues, and therefore
any significant decline in their collective revenues could adversely impact
operating results.
Current
financial market volatility could have adverse impacts.
The
capital and credit markets have been experiencing volatility and
disruption. If the current levels of market disruption and volatility
worsen, there can be no assurance that the Company, or its unconsolidated
affiliates, will not experience adverse effects, which may be
material. These effects may include, but are not limited to,
difficulties in accessing the debt capital markets and the commercial paper
market, increased borrowing costs associated with current debt obligations,
higher interest rates in future financings, and a smaller potential pool of
investors and funding sources. Finally, there is no assurance the
Company will have access to the equity capital markets to obtain financing when
necessary or desirable.
A
downgrade (or negative outlook) in or withdrawal of Vectren’s credit ratings
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.
Vectren
operates in an increasingly competitive industry, which may affect its future
earnings.
The
utility industry has been undergoing 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 and is currently in the
first of the three stage process to exit the merchant function in its Ohio
service territory. The state of Indiana has not adopted any
regulation requiring gas choice in the Company’s Indiana service territories;
however, the Company operates under approved tariffs permitting certain
industrial and commercial large volume customers to choose their commodity
supplier. 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. Since Vectren does not have a weather-normalization
mechanism for its electric 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 in 2005 of a normal
temperature adjustment mechanism. Additionally, the implementation of
a straight fixed variable rate design over a two year period per a January 2009
PUCO order will significantly mitigate weather risk related to Ohio residential
gas sales.
Risks
related to the regulation of Vectren’s utility 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 and are exposed to public policy decisions that may negatively
impact the Company’s earnings. 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 approve its
utility-related debt and equity issuances, 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. Further, there are consumer advocates and other
parties which may intervene in regulatory proceedings and affect regulatory
outcomes. 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 and are more volatile, 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.
Climate
Change
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 substantially affect both the costs and operating characteristics
of the Company’s fossil fuel generating plants and possibly natural gas
distribution businesses. Further, any legislation would likely impact
the Company’s generation resource planning decisions. 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. The Company has gathered preliminary estimates
of the costs to comply with a cap and trade approach to controlling greenhouse
gas emissions. A preliminary investigation demonstrated costs to
comply would be significant, first to operating expenses for the purchase of
allowances, and later to capital expenditures as technology becomes available to
control greenhouse gas emissions. However, these compliance cost
estimates are very sensitive to highly uncertain assumptions, including
allowance prices. Costs to purchase allowances that cap greenhouse
gas emissions should be considered a cost of providing electricity, and as such,
the Company believes recovery should be timely reflected in rates charged to
customers. Approximately 22 percent of electric volumes sold in 2008
were delivered to municipal and other wholesale customers. As such,
the Company has some flexibility to modify the level of these transactions to
reduce overall emissions and reduce costs associated with complying with new
environmental regulations.
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, regulations 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 SIGECO’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 Day 3 ancillary services market (ASM), where
MISO provides bid-based regulation and contingency operating reserve markets
which began on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM.
The need
to expend capital for improvements to the regional 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
timely recovers its investment in certain new electric transmission projects
that benefit the MISO infrastructure at a FERC approved rate of
return.
Wholesale
power marketing activities may add volatility to earnings.
Vectren’s
regulated electric utility engages in wholesale power marketing activities that
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 contracts and from time to time
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
and basis risks. 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 is 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.
The
Company’s expectation of greater earnings from coal mining could be adversely
affected by a number of factors.
The
market for Illinois Basin coal reflects limited supply and increased demand,
which has resulted in substantially higher coal
prices. Contracts reflecting these higher prices are in place on
70 percent of 2009 and 2010 planned production. As a result, coal
mining operations are expected to significantly contribute to future
earnings. This expectation is predicated on the ability to access
coal at two new company-owned mines which are currently under development; to
operate existing mines in accordance with Mine Safety and Health Administration
guidelines and recent interpretations of those guidelines; and to manage
production costs and other risks. Other risks, which could adversely
impact these future earnings, include geologic, equipment, and operational
risks; sales contract negotiations and interpretations; supplier and contract
miner performance; the availability of miners, key equipment and commodities;
availability of transportation; and the ability to access/replace coal
reserves.
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.
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 2005 – 2007 are still subject to IRS examination. However,
avenues remain where the IRS could challenge tax credits for the years prior to
2005. As a partner of Pace Carbon, Vectren has reflected cumulative
synfuel tax credits of approximately $101 million in its consolidated results,
of which approximately $45 million were generated since 2004. To date,
Vectren has been in a position to utilize all of the credits
generated.
Catastrophic
events could adversely affect Vectren’s facilities and operations.
Catastrophic
events such as fires, earthquakes, explosions, floods, ice storms, 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; that it will be unable to
react to a pandemic illness; 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.
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
58,100 acres of land with an estimated ready delivery from storage capability of
6.0 BCF of gas with maximum peak day delivery capabilities of 151,000 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 with ProLiance for 17.9 BCF
of prepaid delivery service with a maximum peak day delivery capability of
298,600 MMBTU per day. Indiana Gas’ gas delivery system includes
12,900 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 active underground gas storage fields located in Indiana
covering 6,100 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 with ProLiance for 0.5 BCF of
prepaid delivery service with a maximum peak day delivery capability of 19,200
MMBTU per day. SIGECO's gas delivery system includes 3,200 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 52,200 MCF of manufactured gas per day. In addition to its
propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF
of delivery service with a maximum peak day delivery capability of 246,100 MMBTU
per day. While the Company still has title to this delivery
capability, it has released it to those now supplying the Ohio operations with
natural gas, and those suppliers are responsible for the demand
charges. The Ohio operations’ gas delivery system includes 5,500
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, 2008, 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 924 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 32 substations with an
installed capacity of 4,200 megavolt amperes (Mva). The electric
distribution system includes 4,200 pole miles of lower voltage overhead lines
and 349 trench miles of conduit containing 2,000 miles of underground
distribution cable. The distribution system also includes 98
distribution substations with an installed capacity of 2,900 Mva and 54,000
distribution transformers with an installed capacity of 2,500
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 which is identified
in Item 1.
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 2008 and 2007, 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
|
||||||||||
|
2008
|
||||||||||||
|
First
Quarter
|
$ | 0.325 | $ | 29.20 | $ | 25.35 | ||||||
|
Second
Quarter
|
0.325 | 32.20 | 26.66 | |||||||||
|
Third
Quarter
|
0.325 | 31.74 | 26.05 | |||||||||
|
Fourth
Quarter
|
0.335 | 29.00 | 19.48 | |||||||||
|
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 | |||||||||
On
January 29, 2009 the board of directors declared a dividend of $0.335 per share,
payable on March 2, 2009, to common shareholders of record on February 13,
2009.
As of
January 31, 2009, there were 10,005 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,
2008.
|
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
|
33,841 | $ | 27.24 | - | - | |||||||||||
|
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 49 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)
|
2008
|
2007
|
2006
|
2005
|
2004
|
|||||||||||||||
|
Operating
Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 2,484.7 | $ | 2,281.9 | $ | 2,041.6 | $ | 2,028.0 | $ | 1,689.8 | ||||||||||
|
Operating
income
|
$ | 263.4 | $ | 260.5 | $ | 220.5 | $ | 213.1 | $ | 199.5 | ||||||||||
|
Net
income
|
$ | 129.0 | $ | 143.1 | $ | 108.8 | $ | 136.8 | $ | 107.9 | ||||||||||
|
Average
common shares outstanding
|
78.3 | 75.9 | 75.7 | 75.6 | 75.6 | |||||||||||||||
|
Fully
diluted common shares outstanding
|
78.9 | 76.6 | 76.2 | 76.1 | 75.9 | |||||||||||||||
|
Basic
earnings per share
|
||||||||||||||||||||
|
on
common stock
|
$ | 1.65 | $ | 1.89 | $ | 1.44 | $ | 1.81 | $ | 1.43 | ||||||||||
|
Diluted
earnings per share
|
||||||||||||||||||||
|
on
common stock
|
$ | 1.63 | $ | 1.87 | $ | 1.43 | $ | 1.80 | $ | 1.42 | ||||||||||
|
Dividends
per share on common stock
|
$ | 1.31 | $ | 1.27 | $ | 1.23 | $ | 1.19 | $ | 1.15 | ||||||||||
|
Balance
Sheet Data:
|
||||||||||||||||||||
|
Total
assets
|
$ | 4,632.9 | $ | 4,296.4 | $ | 4,091.6 | $ | 3,868.1 | $ | 3,586.9 | ||||||||||
|
Long-term
debt, net
|
$ | 1,247.9 | $ | 1,245.4 | $ | 1,208.0 | $ | 1,198.0 | $ | 1,016.6 | ||||||||||
|
Redeemable
preferred stock
|
$ | - | $ | - | $ | - | $ | - | $ | 0.1 | ||||||||||
|
Common
shareholders' equity
|
$ | 1,351.6 | $ | 1,233.7 | $ | 1,174.2 | $ | 1,143.3 | $ | 1,094.8 | ||||||||||
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS
OF OPERATIONS AND FINANCIAL CONDITION
In this
discussion and analysis, the Company analyzes contributions to consolidated
earnings and earnings per share from its Utility Group and Nonutility Group
separately since each operates 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.
|
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. These non-gaap
measures are used by management to evaluate the performance of individual
businesses. Accordingly management believes these measures are
useful to investors in understanding each business’ contribution to
consolidated earnings per share and analyzing period to period
changes.
|
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)
|
2008
|
2007
|
2006
|
|||||||||
|
Net
income
|
$ | 129.0 | $ | 143.1 | $ | 108.8 | ||||||
|
Attributed
to:
|
||||||||||||
|
Utility
Group
|
$ | 111.1 | $ | 106.5 | $ | 91.4 | ||||||
|
Nonutility
Group
|
18.9 | 37.0 | 18.1 | |||||||||
|
Corporate
& Other
|
(1.0 | ) | (0.4 | ) | (0.7 | ) | ||||||
|
Basic
earnings per share
|
$ | 1.65 | $ | 1.89 | $ | 1.44 | ||||||
|
Attributed
to:
|
||||||||||||
|
Utility
Group
|
$ | 1.42 | $ | 1.40 | $ | 1.21 | ||||||
|
Nonutility
Group
|
0.24 | 0.49 | 0.24 | |||||||||
|
Corporate
& Other
|
(0.01 | ) | - | (0.01 | ) | |||||||
Results
For the
year ended December 31, 2008, earnings were $129.0 million, or $1.65 per share,
compared to $143.1 million, or $1.89 per share in 2007, and $108.8 million, or
$1.44 per share, in 2006.
While
utility results increased in 2008 compared to 2007 primarily as a result of base
rate increases, results reflect decreased earnings from nonutility operations,
primarily ProLiance and Coal Mining. Additionally, as more fully
described below, 2008 includes an approximate $0.08 per share impairment charge
associated with legacy nonutility commercial real estate
investments.
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 in 2007 also reflect increased earnings from
the Company’s nonutility operations, primarily Energy Marketing and Services,
Energy Infrastructure Services, and increased synfuel-related
results.
Utility
Group
In 2008,
the Utility Group’s earnings were $111.1 million compared to $106.5 million in
2007. The 4 percent increase in utility earnings is due primarily to
a full year of base rate changes in the Indiana service territories and
increased earnings from wholesale power operations. Increases were
offset somewhat by increased operating costs associated with maintenance and
reliability programs contemplated in the base rate cases and favorable weather
in 2007.
In 2007
compared to 2006, the increase in Utility Group earnings primarily 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 margins. The increase was offset
somewhat by increased operating costs including depreciation expense in 2007 and
a lower effective tax rate in 2006.
In the
Company’s electric and Ohio natural gas service territories which are not
protected by weather normalization mechanisms, management estimates the margin
impact of weather to be approximately $1.2 million favorable or $0.01 per share
compared to 30-year normal temperatures in 2008. In 2007 management
estimates a $5.5 million favorable impact on margin compared to normal or $0.04
per share, and in 2006 an $8.3 million unfavorable impact on margin compared to
normal or $0.07 per share.
Nonutility
Group
The
Nonutility Group’s earnings were $18.9 million in 2008, compared to earnings of
$37.0 million in 2007 and $18.1 million in 2006. The Company’s
primary nonutility operations contributed $24.8 million, compared to $33.7
million in 2007 and $24.5 million in 2006. Primary nonutility
operations are Energy Marketing and Services companies, Coal Mining operations,
and Energy Infrastructure Services companies.
In 2008
compared to 2007, primary nonutility group results decreased $8.9 million. Coal
Mining operated at a loss and results were approximately $6.6 million lower than
the prior year due primarily to lower production and increased operating
costs. ProLiance’s earnings were $3.6 million lower than the prior
year and reflect lower operating results as well as a reserve for the FERC
matter described herein. The results from the other primary
nonutility operations also reflect increased earnings from performance
contracting and renewable energy construction operations performed through
Energy Systems Group and retail gas marketing operations performed through
Vectren Source. Miller Pipeline’s (Miller) results were generally
flat compared to the prior year, which was a record year in terms of earnings
contribution.
Primary
nonutility group results increased $9.2 million in 2007 compared to
2006. The increase was primarily attributable to higher Miller
earnings and the unfavorable impact of the ProLiance litigation settlement
recorded in the fourth quarter of 2006 totaling $6.6 million. 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
Vectren Source 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.
Other
nonutility businesses operated at a loss of $5.9 million in 2008, compared to
earnings of $0.3 million in 2007 and a loss of $1.1 million in
2006. Other nonutility businesses include legacy investments,
including investments in commercial real estate and also included the Company’s
former investment in SIGECOM, LLC. As a result of the economy
impacting commercial real estate, during 2008, the Company recorded an
impairment charge associated with its commercial real estate investments
totaling $10.0 million, $5.9 million after tax, or $0.08 per
share. In 2006, the Company sold its investment in SIGECOM, LLC at a
loss of approximately $1.3 million after tax.
In 2007,
the last year of synfuel operations, synfuel-related results generated earnings
of $6.8 million. Of those earnings, which do not continue into 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. 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.
Dividends
Dividends
declared for the year ended December 31, 2008 were $1.31 per share compared to
$1.27 in 2007 and $1.23 per share in 2006. In October 2008, the
Company’s board of directors increased its quarterly dividend to $0.335 per
share from $0.325 per share. The increase marks the 49th
consecutive year Vectren and predecessor companies’ have increased annual
dividends paid.
2009
Ice Storm
On
January 27, 2009, a major ice storm in the Company’s southern Indiana territory
resulted in an extended disruption of electricity to approximately 75,000 of the
Company’s 141,000 electric customers. Electricity was restored to
substantially all customers within one week. Management estimates the
total cost of restoration could approximate $15 to $20 million, the majority of
which is expected to be capitalized as utility plant.
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. Regulated operations consist
of a natural gas distribution business that provides natural gas distribution
and transportation services to nearly two-thirds of Indiana and to west central
Ohio and an electric transmission and distribution business, which provides
electric distribution services primarily to southwestern Indiana, and the
Company’s power generating and wholesale power operations. In total,
these regulated operations supply natural gas and/or electricity to over one
million customers. Utility Group operating
results before certain intersegment eliminations and reclassifications for the
years ended December 31, 2008, 2007, and 2006, follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share data)
|
2008
|
2007
|
2006
|
|||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Electric
utility
|
524.2 | 487.9 | 422.2 | |||||||||
|
Other
|
1.8 | 1.7 | 1.8 | |||||||||
|
Total
operating revenues
|
1,958.7 | 1,759.0 | 1,656.5 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
983.1 | 847.2 | 841.5 | |||||||||
|
Cost
of fuel & purchased power
|
182.9 | 174.8 | 151.5 | |||||||||
|
Other
operating
|
300.3 | 266.1 | 239.0 | |||||||||
|
Depreciation
& amortization
|
165.5 | 158.4 | 151.3 | |||||||||
|
Taxes
other than income taxes
|
72.3 | 68.1 | 64.2 | |||||||||
|
Total
operating expenses
|
1,704.1 | 1,514.6 | 1,447.5 | |||||||||
|
OPERATING
INCOME
|
254.6 | 244.4 | 209.0 | |||||||||
|
Other
income - net
|
4.0 | 9.4 | 7.6 | |||||||||
|
Interest
expense
|
79.9 | 80.6 | 77.5 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
178.7 | 173.2 | 139.1 | |||||||||
|
Income
taxes
|
67.6 | 66.7 | 47.7 | |||||||||
|
NET
INCOME
|
$ | 111.1 | $ | 106.5 | $ | 91.4 | ||||||
|
CONTRIBUTION
TO VECTREN BASIC EPS
|
$ | 1.42 | $ | 1.40 | $ | 1.21 | ||||||
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. 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 to these customers 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
had lost margin recovery since October 2006. The Ohio lost margin
recovery mechanism ended when new base rates went into effect in February
2009. This mechanism was replaced by a rate design, commonly referred
to as a straight fixed variable rate design, which is more dependent on service
charge revenues and less dependent on volumetric revenues than previous rate
designs. This new rate design, which will be phased in over a two year period,
also prospectively mitigates some weather risk in Ohio. SIGECO’s
electric service territory has neither NTA nor lost margin recovery
mechanisms.
Gas and
electric margin generated from sales to large customers (generally industrial
and other contract customers) is primarily impacted by overall economic
conditions and changes in demand for those customers’ products. The
recent recession may have some negative impact on both gas and electric large
customers. This impact may include tempered growth, significant
conservation measures, and perhaps even plant closures or
bankruptcies. While no one industrial customer comprises 10 percent
of consolidated revenues, the top five industrial electric customers comprise
approximately 17 percent of electric utility revenues, and therefore any
significant decline in their collective revenues could adversely impact
operating results. Deteriorating economic conditions may also lead to
continued lower residential and commercial customer
counts.
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 latest Indiana service territory rate cases,
implemented in 2007 and 2008 also provide for the tracking of MISO revenues and
costs, as well as the gas cost component of bad debt expense based on historical
experience and unaccounted for gas. Unaccounted for gas is also
tracked in the Ohio service territory.
Electric
wholesale 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)
Gas
Utility margin and throughput by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Gas
utility revenues
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Cost
of gas sold
|
983.1 | 847.2 | 841.5 | |||||||||
|
Total
gas utility margin
|
$ | 449.6 | $ | 422.2 | $ | 391.0 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 385.1 | $ | 360.9 | $ | 330.2 | ||||||
|
Industrial
customers
|
52.2 | 48.7 | 48.0 | |||||||||
|
Other
|
12.3 | 12.6 | 12.8 | |||||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
114.8 | 108.4 | 97.7 | |||||||||
|
Industrial
customers
|
91.5 | 86.2 | 84.9 | |||||||||
|
Total
sold & transported volumes
|
206.3 | 194.6 | 182.6 | |||||||||
For the
year ended December 31, 2008, gas utility margins were $449.6 million, an
increase of $27.4 million compared to 2007. The Vectren North base
rate increase, effective February 14, 2008 added $11.8 million in
margin. Also impacting year over year results was the Vectren South
base rate increase, effective August 1, 2007, increasing margin for the full
2008 year approximately $3.6 million. In 2008, Ohio weather was 8
percent colder than the prior year and resulted in an estimated increase in
margin of approximately $3.2 million compared to 2007. Operating
costs, including revenue and usage taxes, directly recovered in margin,
increased gas margin $7.8 million. The average cost per dekatherm of gas
purchased for the year ended December 31, 2008, was $9.61 compared to $8.14 in
2007 and $8.64 in 2006.
Gas
Utility margins increased $31.2 million in 2007 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, directly recovered 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.
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)
|
2008
|
2007
|
2006
|
|||||||||
|
Electric
utility revenues
|
$ | 524.2 | $ | 487.9 | $ | 422.2 | ||||||
|
Cost
of fuel & purchased power
|
182.9 | 174.8 | 151.5 | |||||||||
|
Total
electric utility margin
|
$ | 341.3 | $ | 313.1 | $ | 270.7 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 218.6 | $ | 198.6 | $ | 162.9 | ||||||
|
Industrial
customers
|
82.9 | 78.3 | 70.2 | |||||||||
|
Municipals
& other customers
|
7.3 | 15.3 | 24.0 | |||||||||
|
Subtotal:
Retail
|
$ | 308.8 | $ | 292.2 | $ | 257.1 | ||||||
|
Wholesale
margin
|
$ | 32.5 | $ | 20.9 | $ | 13.6 | ||||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
2,850.5 | 3,042.9 | 2,789.7 | |||||||||
|
Industrial
customers
|
2,409.1 | 2,538.5 | 2,570.4 | |||||||||
|
Municipals
& other
|
63.8 | 635.1 | 644.4 | |||||||||
|
Total
retail & firm wholesale volumes sold
|
5,323.4 | 6,216.5 | 6,004.5 | |||||||||
Retail
Electric
retail utility margin was $308.8 million for the year ended December 31, 2008,
an increase of approximately $16.6 million compared to 2007. The base
rate increase that went into effect on August 15, 2007, produced incremental
margin of $27.0 million year over year when netted with municipal contracts that
were allowed to expire. Management estimates the year over year
decreases in usage by residential and commercial customers due to weather, which
was very warm the prior summer, to be $7.5 million. Other usage
declines due in part to a weakening economy and conservation measures were the
primary reason for the remaining decrease.
In 2007,
electric retail utility margins increased $35.1 million when compared to
2006. 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 2006. Recovery of pollution control investments and
expenses increased margin $5.5 million year over year.
Margin
from Wholesale Activities
Periodically,
generation capacity is in excess of native load. 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 and Real Time
markets.
Further
detail of Wholesale
activity follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Off-system
sales, net of sharing in 2008
|
$ | 23.2 | $ | 16.9 | $ | 14.2 | ||||||
|
Transmission
system sales
|
9.3 | 4.0 | 3.5 | |||||||||
|
Other
|
- | - | (4.1 | ) | ||||||||
|
Total
wholesale margin
|
$ | 32.5 | $ | 20.9 | $ | 13.6 | ||||||
For the
year ended December 31, 2008, wholesale margins were $32.5 million, representing
an increase of $11.6 million, compared to 2007.
During
2008, margin from off-system sales retained by the Company increased $6.3
million. The Company experienced higher wholesale power marketing
margins due to the increase in off peak volumes available for sale off system,
driven primarily by expiring municipal contracts, and increases in wholesale
prices. The base rate case effective August 17, 2007, requires that
wholesale margin from off-system sales earned above or below $10.5 million be
shared equally with customers, and 2008 results reflect the impact of that
sharing. Off-system sales totaled 1,512.9 GWh in 2008, compared to
921.3 GWh in 2007 and 889.4 GWh in 2006.
Beginning
in June 2008, the Company began earning a return on electric transmission
projects constructed by the Company in its service territory that benefit
reliability throughout the region. These returns primarily account
for the year over year increase of $4.8 million in transmission system
sales.
For the
year ended December 31, 2007, wholesale margins were $20.9 million, which
represents an increase of $7.3 million, compared to 2006. The
increase is primarily due to losses on financial contracts experienced in 2006
and higher fourth quarter wholesale prices. In 2006, the availability
of excess capacity was reduced by scheduled outages associated with the
installation of environmental compliance equipment.
Utility Group Operating
Expenses
Other
Operating
For the
year ended December 31, 2008, other operating expenses were
$300.3 million, which represents an increase of $34.2 million, compared to
2007. Costs in 2008 resulting from increased maintenance and other
reliability activities, including amortization of prior deferred costs
contemplated in base rate increases, increased approximately $35.3 million year
over year. Operating costs that are directly recovered in utility
margin increased $4.2 million year over year. Costs associated with
lower performance compensation and share based compensation and other cost
reductions partially offset these increases.
In 2007,
other operating
expenses increased $27.1 million compared to 2006. Operating
costs that are directly recovered in utility margin, including costs funding
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
increased $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.
Depreciation
& Amortization
Depreciation
expense increased $7.1 million in 2008 compared to 2007 as well as in 2007
compared to 2006. Expense in 2008 and 2007 includes $3.8 million and
$1.8 million, respectively of increased amortization associated with prior
electric demand side management costs pursuant to the August 15,
2007 electric base rate order. The remaining increases are also
attributable to increased utility plant in service.
Taxes
Other Than Income Taxes
Taxes
other than income taxes increased $4.2 million in 2008 compared to 2007 and
increased $3.9 million in 2007 compared 2006. The increases are
primarily attributable to higher utility receipts, excise, and usage
taxes. These variations resulted primarily from volatility in
revenues and gas volumes sold.
Other
Income-Net
Other-net reflects income of
$4.0 million in 2008 compared to $9.4 million in 2007 and $7.6 million in
2006. The decrease in 2008 compared to 2007 is primarily due to lower
returns associated with investments that fund deferred compensation arrangements
and lower interest income. The increase in 2007 compared to 2006
relates primarily to increased AFUDC due to increased capital spending and
higher interest income.
Utility Group Interest
Expense
For the
year ended December 31, 2008, interest expense was $79.9 million, a decrease of
$0.7 million compared to 2007, as lower average short-term debt levels and lower
average short-term interest rates were partially offset by higher long-term
balances and interest rates.
In 2007,
interest expense increased $3.1 million compared to 2006. The
increase is primarily driven by rising interest rates during the period and is
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. 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 $0.9 million in 2008 compared to 2007 and $19.0 million in 2007
compared to 2006. The changes are impacted primarily by fluctuations
in pre-tax income and a lower effective tax rate in 2008 and 2006.
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 Act
Initiatives
In March
of 2005, the USEPA finalized the Clean Air Interstate Rule (CAIR). CAIR is an
allowance cap and trade program requiring further reductions from coal-burning
power plants in NOx emissions beginning January 1, 2009 and SO2 emissions
beginning January 1, 2010, with a second phase of reductions in 2015. On
July 11, 2008, the US Court of Appeals for the District of Columbia vacated the
federal CAIR regulations. Various parties filed motions for
reconsideration, and on December 23, 2008, the Court reinstated the CAIR
regulations and remanded the regulations back to the USEPA for promulgation of
revisions in accordance with the Court’s July 11, 2008 Order. Thus,
the original version of CAIR promulgated in March of 2005 remains effective
while USEPA revises it per the Court’s guidance. It is possible that
a revised CAIR will require further reductions in NOx and SO2 from
SIGECO’s generating units. SIGECO is in compliance with the current
CAIR Phase I annual NOx reduction requirements in effect on January 1,
2009. Utilization of the Company’s inventory of NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of the these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. It is quite possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress. It is also possible that the USEPA will promulgate
a revised mercury regulation in 2009.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. 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 allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. Through
December 31, 2008, the Company has invested approximately $97.6 million in this
project. The scrubber was placed into service on January 1, 2009, and
the Company expects the total project investment to approximate $100 million
once all post in-service investments are completed. Recovery through
a rider mechanism of associated operating expenses including depreciation
expense associated with the scrubber also began on January 1,
2009. With the SO2 scrubber
fully operational, SIGECO is positioned for compliance with the additional
SO2
reductions required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s
coal fired generating fleet is 100 percent scrubbed for SO2 and 90
percent controlled for NOx. SIGECO's investments in scrubber, SCR and
fabric filter technology allows for compliance with existing regulations and
should position it to comply with future reasonable pollution control
legislation, if and when, reductions in mercury and further reductions in NOx
and SO2 are
promulgated by USEPA.
Climate
Change
Vectren
is committed to responsible environmental stewardship and conservation efforts
as demonstrated by its proactive approach to balancing environmental and
customer needs. While scientific uncertainties exist and the debate surrounding
global climate change is ongoing, the growing understanding of the science of
climate change would suggest a strong potential for adverse economic and social
consequences should world-wide carbon dioxide (CO2) and other
greenhouse gas emissions continue at present levels.
The need
to reduce CO2 and other
greenhouse gas emissions, yet provide affordable energy requires thoughtful
balance. For these reasons, Vectren supports a national climate change policy
with the following elements:
|
·
|
An
inclusive scope that involves all sectors of the economy and sources of
greenhouse gases, and recognizes early actions and investments made to
mitigate greenhouse gas emissions;
|
|
·
|
Provisions
for enhanced use of renewable energy sources as a supplement to base load
coal generation including effective energy conservation, demand side
management and generation efficiency
measures;
|
|
·
|
A
flexible market-based cap and trade approach with zero cost allowance
allocations to coal-fired electric generators. The approach
should have a properly designed economic safety valve in order to reduce
or eliminate extreme price spikes and potential price volatility. A long
lead time must be included to align nearer-term technology capabilities
and expanded generation efficiency and other enhanced renewable
strategies, ensuring that generation sources will rely less on natural gas
to meet short term carbon reduction requirements. This new
regime should allow for adequate resource and generation planning and
remove existing impediments to efficiency enhancements posed by the
current New Source Review provisions of the Clean Air
Act;
|
|
·
|
Inclusion
of incentives for investment in advanced clean coal technology and support
for research and development; and
|
|
·
|
A
strategy supporting alternative energy technologies and biofuels and
increasing the domestic supply of natural gas to reduce dependence on
foreign oil and imported natural
gas.
|
Current
Initiatives to Increase Conservation and Reduce Emissions
The
Company is committed to its policy on climate change and conservation. Evidence
of this commitment includes:
|
·
|
Focusing
the Company’s mission statement and purpose on corporate sustainability
and the need to help customers conserve and manage energy
costs;
|
|
·
|
Recently
executing a 20 year contract to purchase 30MW of wind energy generated by
a wind farm in Benton County,
Indiana;
|
|
·
|
Evaluating
other renewable energy projects to complement base load coal fired
generation in advance of mandated renewable energy portfolio
standards;
|
|
·
|
Implementing
conservation initiatives in the Company’s Indiana and Ohio gas utility
service territories;
|
|
·
|
Participation
in an electric conservation and demand side management collaborative with
the OUCC and other customer advocate
groups;
|
|
·
|
Evaluating
potential carbon requirements with regard to new generation, other fuel
supply sources, and future environmental compliance
plans;
|
|
·
|
Reducing
the Company’s carbon footprint by measures such as purchasing hybrid
vehicles, and optimizing generation
efficiencies;
|
|
·
|
Developing
renewable energy and energy efficiency performance contracting projects
through its wholly owned subsidiary, Energy Systems
Group.
|
Legislative
Actions and Other Climate Change Initiatives
There are
currently several forms of legislation being circulated at the federal level
addressing the climate change issue. These proposals generally
involve either: 1) a “cap and trade” approach where there is a progressive cap
on greenhouse gas emissions and an auctioning and subsequent trading of
allowances among those that emit greenhouse gases or 2) a carbon
tax. Currently no legislation has passed either house of
Congress.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in the State
of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas
Reduction Accord, and its legislature has in the recent past debated, but did
not pass, renewable energy portfolio standards. It is expected that
the Indiana State legislature will address a renewable energy portfolio standard
again in 2009.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from new motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. Should the USEPA find such endangerment, it is likely
that major stationary sources will be subject to regulation under the
Act. In 2008, the USEPA published its Advanced Notice of Proposed
Rulemaking in which the agency solicited comment as to whether it is appropriate
or effective to regulate greenhouse gas emissions under the Act. The
Obama administration has asserted that it will act on the endangerment finding
in the absence of comprehensive federal legislation within the next 18
months.
Impact
of Legislative Actions and Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants,
nonutility coal mining operations, and possibly natural gas distribution
businesses. Further, any legislation would likely impact the Company’s
generation resource planning decisions. 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. The Company has gathered preliminary estimates of the costs to
comply with a cap and trade approach to controlling greenhouse gas
emissions. A preliminary investigation demonstrated costs to comply
would be significant, first to operating expenses for the purchase of
allowances, and later to capital expenditures as technology becomes available to
control greenhouse gas emissions. However, these compliance cost
estimates are very sensitive to highly uncertain assumptions, including
allowance prices. Costs to purchase allowances that cap greenhouse
gas emissions should be considered a cost of providing electricity, and as such,
the Company believes recovery should be timely reflected in rates charged to
customers. Approximately 22 percent of electric volumes sold in 2008
were delivered to municipal and other wholesale customers. As such,
the Company has some flexibility to modify the level of these transactions to
reduce overall emissions and reduce costs associated with complying with new
environmental regulations.
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 owned or
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 cumulative costs
that it reasonably expects to incur totaling approximately $21.6
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 $20.5
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 cumulative costs that it reasonably expects to incur totaling
approximately $8.7 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 of $8.0 million.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. 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. As of December 31, 2008, approximately $6.5 million is
included in Other
Liabilities related to the remediation of these sites.
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. The GCA clause allows 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 a variable
benchmark based on NYMEX natural gas prices, is also recovered through
regulatory proceedings. The IURC approved agreement authorizing this
recovery expires in April 2010, and is subject to automatic annual
renewals.
GCA and
FAC procedures involve periodic filings and IURC 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. These
earnings tests have not had any material impact to the Company’s recent
operating results.
Prior to
October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery
(GCR) clause. The GCR clause operated similar to the GCA clause in
Indiana. The PUCO periodically audited the GCR rates. The period
from November 2005 to September 2008, the final GCR period subject to audit, is
currently under audit by the PUCO. After October 1st, the
Company is no longer the supplier, and the GCR is no longer
necessary.
Vectren Energy Delivery
Ohio, Inc. (VEDO) Gas Base Rate Order Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also adjusts the rate design that will be used to collect the agreed-upon
revenue from VEDO's residential customers. The order authorizes the
use of a straight fixed variable rate design which places all, or most, of the
fixed cost recovery in the customer service charge. Using a phased in
approach, revenues based on volumes sold will be entirely replaced with a fixed
charge after one year. A straight fixed variable design
mitigates some weather risk as well as the effects of declining usage, similar
to the Company’s lost margin recovery mechanism, which expired when this new
rate design went into effect in February 2009. In 2008, results include
approximately $4.3 million of revenue from the existing lost margin recovery
mechanism that will not continue once this base rate increase is in
effect. The OCC has filed a request for rehearing on the rate design
finding by the PUCO. The rehearing request mirrors similar requests filed
by the OCC in each case where the PUCO has approved similar rate designs, and
all such requests have been denied.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of bad debt and percent of
income payment plan (PIPP) expenses; base rate recovery of pipeline integrity
management expense; timely recovery of costs associated with the accelerated
replacement of bare steel and cast iron pipes, as well as certain service
risers; and expanded conservation programs now totaling up to $5 million in
annual expenditures.
Vectren Energy Delivery
Ohio, Inc. Begins Process to Exit the Merchant Function
On August
20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers
to provide the gas commodity to the Company for resale to its customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. This auction, which is effective from October 1, 2008 through
March 31, 2010, is the initial step in exiting the merchant function in the
Company’s Ohio service territory. The approach eliminates the
need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits. On October 1st, VEDO’s
entire natural gas inventory was transferred, receiving proceeds of
approximately $107 million. The PUCO has also provided for an Exit
Transition Cost rider, which allows the Company to recover costs associated with
the transition. As the cost of gas is currently passed through to
customers through a PUCO approved recovery mechanism, the impact of exiting the
merchant function should not have a material impact on Company earnings or
financial condition.
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
the settlement agreement reached in its Vectren North gas rate case. The
order provided for a base rate increase of $16.3 million and a return on equity
(ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate
base of approximately $793 million. The order 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 regulatory
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 a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s electric rate case. The order
provided for an approximate $60.8 million electric rate increase to cover the
Company’s cost of system growth, maintenance, safety and reliability. The
order provided 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 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 ROE of 10.4
percent.
Vectren South Gas Base Rate
Order Received
On August
1, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s gas rate case. The order provided
for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an
overall rate of return of 7.2 percent on rate base of approximately $122
million. The order also provided 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 regulatory
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 a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
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. Since April 1, 2005, the Company has been an active participant
in the MISO energy markets, bidding its owned generation into the Day Ahead and
Real Time markets and procuring 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 as generation capacity is
in excess of that needed to serve native load and is only occasionally in a net
purchase position. 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. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO day ahead and real-time markets. Net revenues from wholesale
activities included in Electric Utility revenues
totaled $57.6 million in 2008, $39.8 million in 2007 and $29.8 million in
2006.
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. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered/refunded through tracking
mechanisms.
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 Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM.
The need
to expend capital for improvements to the regional 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
timely recovers its investment in certain new electric transmission projects
that benefit the MISO infrastructure at a FERC approved rate of
return.
One such
project is an interstate 345 kilovolt transmission line that will connect
Vectren’s A B Brown Station to a station in Indiana owned by Duke Energy to the
north and to a station in Kentucky owned by Big Rivers Electric Corporation to
the south. Throughout the project, SIGECO is to recover an
approximate 10 percent return, inclusive of the FERC approved equity rate
of return of 12.38 percent, on capital investments through a
rider mechanism which is periodically updated for actual costs incurred.
Of the total investment, which is expected to approximate $70 million, as of
December 31, 2008, the Company has invested approximately $3.1
million. The Company expects this project to be operational
in 2011. At that time, any operating expenses including depreciation
expense are also expected to be recovered through a FERC approved rider
mechanism. Further, the approval allows for recovery of expenditures made
even in the event currently unforeseen difficulties delay or permanently halt
the project.
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 legacy businesses that have
invested in energy-related opportunities and services, real estate, and
leveraged leases, among other investments. The Nonutility Group
supports the Company’s regulated utilities pursuant to service contracts by
providing natural gas supply services, coal, and infrastructure
services. Nonutility Group earnings for the years ended December 31,
2008, 2007, and 2006, follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share amounts)
|
2008
|
2007
|
2006
|
|||||||||
|
NET
INCOME
|
$ | 18.9 | $ | 37.0 | $ | 18.1 | ||||||
|
CONTRIBUTION
TO VECTREN BASIC EPS
|
$ | 0.24 | $ | 0.49 | $ | 0.24 | ||||||
|
NET
INCOME ATTRIBUTED TO:
|
||||||||||||
|
Energy
Marketing & Services
|
$ | 18.0 | $ | 22.3 | $ | 14.9 | ||||||
|
Mining
Operations
|
(4.6 | ) | 2.0 | 5.0 | ||||||||
|
Energy
Infrastructure Services
|
11.4 | 9.4 | 4.6 | |||||||||
|
Other
Businesses
|
(5.9 | ) | 0.3 | (1.1 | ) | |||||||
|
Synfuels-related
|
- | 3.0 | (5.3 | ) | ||||||||
Impact
of the Current Recession
A
prolonged recession may include a lower level of economic activity and
uncertainty regarding energy prices and other key factors that impact the
Nonutility Group. Economic declines may be accompanied by a decrease
in demand for products and services offered by nonutility operations and
therefore lower revenues for those products and services. The recent
economic downturn may have some negative impact on utility industry spending for
construction projects, demand for coal, and spending on performance contracting
and renewable energy expansion. It is also possible that a prolonged
recession could result in further reductions in the value of certain nonutility
real estate and other legacy investments.
Energy
Marketing & Services
Energy
Marketing and Services is comprised of the Company’s gas marketing operations,
energy management services, and retail gas supply
operations. Results, inclusive of holding company costs, from Energy
Marketing and Services for the year ended December 31, 2008, were earnings of
$18.0 million compared to $22.3 million in 2007 and $14.9 million in
2006.
ProLiance
ProLiance,
a nonutility energy marketing affiliate of Vectren and Citizens, 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’
utilities. 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.
During
2008, ProLiance’s earnings contribution was $19.3 million compared to $22.9
million in 2007 and $18.3 million in 2006. The $3.6 million decrease
in 2008 compared to 2007 reflects lower operating results and a reserve for the
FERC matter described below. 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,
compared to 2006. ProLiance’s storage capacity was 42 BCF at December 31, 2008
compared to 40 BCF at December 31, 2007 and 35 BCF at the end of
2006.
Regulatory
Matter
ProLiance
self reported to the Federal Energy Regulatory Commission (FERC) in October 2007
possible non-compliance with the FERC’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 believes that it has adequately reserved for
this matter. Although the outcome of any legal or regulatory
proceedings resulting from these matters cannot be predicted, the final
resolution of these matters is not expected to have a material impact on the
Company’s consolidated operating results, financial position or cash
flows.
Investment
in Liberty Gas Storage
Liberty
Gas Storage, LLC (Liberty) is a joint venture between a subsidiary of ProLiance
and a subsidiary of Sempra Energy (SE). ProLiance is the minority
member with a 25 percent interest, which it accounts for using the equity
method. Liberty holds a long-term lease of storage and mineral rights
associated with existing salt dome storage caverns in southern Louisiana, near
Sulphur, Louisiana. Liberty also owns a second site near Hackberry,
Louisiana with three additional existing salt dome storage
caverns. The members anticipated it would provide high deliverability
storage services via the salt dome caverns at both locations and, once developed
under current plans, there would be approximately 35 billion cubic feet of
working gas capacity at the two sites. ProLiance has a long
term contract for approximately 5 Bcf of working gas
capacity. The total project investment at the Sulphur site
through December 31, 2008 is approximately $200 million. ProLiance’s
portion of the investment is estimated at approximately $50
million.
Based on
information received from SE concerning the maximum estimated possible exposure,
ProLiance estimates that a maximum of $35 million of its total investment would
be at risk (the Company’s proportionate share of the investment would be $21
million). The Company believes that such a charge, should it
occur, would not have a material adverse effect on either the Company’s or
ProLiance’s financial position, cash flows, or liquidity, but it could be
material to net income in any one accounting period. Further, it is
not expected that the delay in Liberty’s development will impact ProLiance’s
ability to meet the needs of its customers.
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 $1.9 million in
2008, compared to $1.2 million in 2007 and a loss of $0.4 million in
2006. Results in 2008 were impacted by a $0.5 million gain on the
sale of its Georgia customer base. The earnings increase in 2007
compared to 2006 is primarily due to lower marketing costs in 2007 and mild
weather in 2006. Vectren Source’s customer count at December 31,
2008, was approximately 170,000 customers. This customer base
reflects nearly 40,000 equivalent customers in VEDO’s service territory as part
of VEDO’s process of exiting the merchant function and a loss of customers due
to exiting the Georgia market. Vectren Source began providing
services to these Ohio customers on October 1, 2008. Customer count
at the end of 2007 and 2006 was 161,000 and 150,000
respectively.
Coal
Mining
Coal
Mining mines and sells coal to the Company’s utility operations and to third
parties through its wholly owned subsidiary Vectren Fuels, Inc.
(Fuels). Coal Mining, inclusive of holding company costs, operated at
a loss of $4.6 million in 2008, compared to earnings of $2.0 million in 2007 and
$5.0 million in 2006. The decrease in earnings in 2008 compared to
2007 was primarily due to lower production and increased roofing structure
costs as a result of revised regulatory guidelines from the Mine Safety and
Health Administration (MSHA) which necessitated changes to the mining
plan. As a result, the yield at the Prosperity mine decreased to 56
percent in 2008 down from 60 percent in 2007 and 2006. In addition,
2008 has been impacted by higher diesel fuel costs and unfavorable geologic
conditions at the Company’s surface mine, which has resulted in more costs to
enhance the BTU content of mined coal. The decline in earnings in
2007 compared to 2006 was primarily due to the effects of compliance with
revised MSHA seal guidelines and higher sulfur content from coal mined under a
revised mining plan. These decreases are offset somewhat by reduced
operating costs from high wall mining at the Cypress Creek surface
mine.
In April
2006, Fuels announced plans to open two new underground mines near Vincennes,
Indiana. Construction continues at the new underground mines with the
mine substation complete and the wash plant construction and box cut excavation
having commenced in June 2008. Production is expected to begin in mid
2009, with the second mine opening in late 2010. Reserves at
the two mines are estimated at 88 million tons of recoverable number-five coal
at 11,200 BTU (British thermal units) and less than 6-pound sulfur
dioxide. The reserves at these new mines bring total coal reserves to
over 120 million tons. Once in production, the two new mines are
expected to produce 5 million tons of coal per year. Of the total
$170 million investment management estimates to access the reserves, the Company
has invested $68 million in the new mines through December 31,
2008.
The
market for Illinois Basin coal reflects limited supply and increased demand,
which has resulted in substantially higher coal
prices. Contracts reflecting these higher prices are in place on
70 percent of 2009 and 2010 planned production. As a result, coal
mining operations are expected to contribute substantial future
earnings.
Energy
Infrastructure Services
Energy
Infrastructure Services provides underground construction and repair to utility
infrastructure through Miller Pipeline Corporation (Miller) and energy
performance contracting and renewable energy services through Energy Systems
Group, LLC (ESG). Inclusive of holding company costs, Energy
Infrastructure’s operations contributed earnings of $11.4 million in 2008,
compared to $9.4 million in 2007 and $4.6 million in 2006.
Miller
Pipeline
Miller’s
2008 earnings were $6.2 million compared to $6.1 million in 2007 and $2.3
million in 2006. In 2007, Miller benefited from more large gas
construction projects and pricing increases. Vectren’s 100 percent
ownership of Miller effective July 1, 2006 also contributed to the increase in
2007 compared to 2006. As a result of the recession, earnings in 2009
are likely to be impacted by less capital spending by Miller’s large customers
for their infrastructure programs.
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 increases in
Other operating expense
totaling $90.9 million in 2007 compared to 2006.
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
earnings were $6.7 million in 2008, compared to $4.0 million in 2007 and $3.1
million in 2006. The increases are primarily due to the continued
focus on energy conservation and sustainability measures by ESG’s customers, as
evidenced by approximately $50 million in new 2008 fourth quarter sales
contracts. Results in 2008 were further favorably impacted by Energy
Efficient Commercial Building federal income tax deductions, commonly referred
to as Internal Revenue Code Section 179D deductions, associated with the
installation of energy efficient equipment. These deductions continue
through 2013. Deductions reflected in the 2008 tax provision include
$1.6 million related to contracts executed in 2007 and 2008. At
December 31, 2008, ESG’s backlog was $65 million, compared to $52 million at
December 31, 2007. The national focus on a comprehensive energy
strategy as evidenced by the new Energy Independence and Security Act of 2007
and legislation supported by the new administration is likely to continue to
favorably impact ESG’s future earnings.
Other
Businesses
Within
the Nonutility business segment, there are legacy investments, outside of
primary operations, involved in energy-related opportunities and services, real
estate, leveraged leases, and other ventures, including investments in the
Haddington Energy Partnerships (Haddington). The earnings impact of
exiting the broadband business in 2006 is also included in Other
Businesses.
As of
December 31, 2008, remaining legacy investments included in the Other Businesses
portfolio total $71.8 million, of which $45.9 million are included in Other nonutility investments
and $25.9 million are included in Investments in unconsolidated
affiliates on the Consolidated Balance
Sheet. Further separation of that remaining investment by type
of investment follows: commercial real estate $21.0 million; Haddington $14.3
million; affordable housing projects $9.6 million; leveraged leases $17.3
million, and other investments, including a note receivable from the City of
Alameda California, $9.6 million.
Other
Businesses reported a loss of $5.9 million 2008, compared to earnings of $0.3
million in 2007 and a loss of $1.1 million in 2006. Results in 2008
reflect a write-down associated with commercial real estate investments, and
results for 2006 reflect a loss on the sale of SIGECOM, LLC
(SIGECOM).
Commercial Real Estate
Charge
The
current economic recession has impacted the value of commercial real estate
investments within this portfolio, and the prospect for recovery of that value
has diminished. During 2008, the Company assessed its commercial real
estate investments for impairment and identified the need to reduce their
carrying values. The impairment charge totaled $10.0 million, $5.9
million after tax, or $0.08 per basic earnings per share. Of the
$10.0 million charge, $5.2 million is included in Other-net and $4.8 million is
included in Other
operating expenses.
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 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. Partnership
operations since that date have been insignificant.
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 2005 – 2007 are still subject to IRS examination. However,
avenues remain where the IRS could challenge tax credits for the years prior to
2005. As a partner of Pace Carbon, Vectren has reflected
cumulative synfuel tax credits of approximately $101 million in its consolidated
results, of which approximately $45 million were generated since 2004. To
date, Vectren has been in a position to utilize all of the credits
generated
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. Because
of high oil prices in 2007, only $6.0 million of the approximate $23.1 million
in tax credits generated were reflected as a reduction to the Company’s income
tax expense. In 2006 high oil prices also phased out 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.
The investment in Pace Carbon resulted
in losses reflected in Equity in earnings
of unconsolidated affiliates totaling $20.0 million in 2007 and
$17.8 million 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 and a loss of $5.3
million in 2006. 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
SFAS
158
The
Company accounts for its pension and post-retirement obligations in accordance
with 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). Under SFAS 158, the Company recognizes the funded
status of its pension plans and postretirement plans. SFAS 158
requires, among other things, 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. These measurement
date provisions were adopted on January 1, 2008. Prior to the
adoption of SFAS 158, Vectren had a September 30 measurement
date. The effects of adopting SFAS 158 were calculated using a
measurement of plan assets and benefit obligations as of September 30, 2007 and
a 15-month projection of periodic cost to December 31, 2008. The
Company recorded three months of that cost totaling $2.7 million, or $1.6
million after tax, to Retained
earnings on January 1, 2008. Related adjustments to Accumulated other comprehensive
income and Regulatory
assets were not material.
SFAS
157
On
January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements”
(SFAS 157), except as it applies to nonfinancial assets and nonfinancial
liabilities. FSP FAS 157-2 delayed the effective date of SFAS 157 for
all nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value on a recurring basis (at least
annually). This FSP deferred the effective date of Statement 157 for
those items to fiscal years beginning after November 15, 2008.
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 impacts how other fair value based
GAAP is applied. The partial adoption of SFAS 157 did not have a
material impact on the Company’s financial position, results of operations or
cash flows. Disclosures impacted by SFAS 157 are included in Note 17
to the consolidated financial statements. The adoption of the
remaining components of SFAS 157 on January 1, 2009 is also not expected to be
material on the Company’s financial position, results of operations or cash
flows.
SFAS
159
Also on
January 1, 2008, the Company adopted 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 choose to
measure many financial instruments and certain other items at fair
value. The Company did not choose to apply the option provided in
SFAS 159 to any of its eligible items; therefore, its adoption did not have any
impact on the Company’s financial statements or results of
operations.
SFAS
141 (Revised 2007)
In
December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS
141R). SFAS 141R 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 141R 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 141R 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 141R 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 No. 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
the impact is not expected to be material to the Company’s financial position or
results of operations.
SFAS
161
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS
161). SFAS 161 enhances the current disclosures under SFAS 133 and
requires that objectives for using derivative instruments be disclosed in terms
of underlying risk and accounting designation in order to better convey the
purpose of derivative use in terms of the risks that the entity is intending to
manage. Entities are required to provide enhanced disclosures about
(a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. Tabular disclosure of fair value amounts and gains and
losses on derivative instruments and related hedged items is
required. SFAS 161 is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
adoption encouraged. The Company will adopt SFAS 161 on January 1,
2009, and the impact is not expected to be material to the Company’s financial
position or results of operations.
SFAS
162
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of
accounting principles and the framework for selecting principles used in the
preparation of financial statements. SFAS No. 162 is effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity
with Generally Accepted Accounting Principles”. The implementation of this
standard will not have a material impact on its financial position and results
of operations.
FSP
EITF 03-6-1
In June
2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted
in Share-Based Payment Transactions Are Participating Securities” (FSP EITF
03-6-1). FSP EITF 03-6-1 clarified that all outstanding unvested share-based
payment awards that contain rights to nonforfeitable dividends participate in
undistributed earnings with common shareholders. Awards of this nature are
considered participating securities and the two-class method of computing basic
and diluted earnings per share must be applied. FSP EITF 03-6-1 is effective for
fiscal years beginning after December 15, 2008. The Company will
adopt FSP EITF 03-6-1on January 1, 2009, and the impact is not expected to be
material to the Company’s financial position or 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. The consolidated financial statement footnotes
describe 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 both debt and equity investments in unconsolidated
entities. 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, if readily available, to the carrying amount of the
note. An impairment analysis of equity 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).
The
current economic recession has impacted the value of commercial real estate
investments within the Other Businesses nonutility portfolio, and the prospect
for recovery of that value has diminished. The Company assessed its
commercial real estate investments for impairment and identified the need to
reduce their carrying values. The impairment charge recorded in 2008
totaled $10.0 million. The assessment was conducted using SFAS No.
114 “Accounting by Creditors for Impairment of a Loan”, APB 18 “The Equity
Method of Accounting for Investments in Common Stock”, and SFAS No. 144
“Accounting for the Impairment or Disposal of Long-Lived Assets”, and their
related amendments and interpretations. An impairment analysis of
notes receivable per SFAS 114 involves the comparison of the investment’s
estimated free cash flows to the stated terms of the note. An
impairment analysis of equity method investments per APB 18 is a comparison of
the investment’s estimated fair value to its carrying amount and an assessment
of whether any decline in fair value is “other than temporary”. Fair
value was estimated primarily using discounted future cash
flows. Calculating free cash flows and the resulting fair value is
subjective and requires judgment concerning growth assumptions, longevity of
cash flows, and discount rates.
Significant
assumptions impacting these analyses were holding periods, net operating income
and capitalization rates, which have increased in the current economic and
credit constrained environment. Related to capitalization rates, the
Company used a 9.75 cap rate to value a suburban Chicago commercial real estate
holding owned by the Company that is currently vacant and a 9.25 cap rate to
value leased commercial real estate located in Charlotte, NC and Birmingham, AL
that serve as collateral for a note receivable. A 50 basis point
increase in those cap rates would have increased the impairment charge by $2.5
million. Actual realized values could differ from these
estimates.
In 2008
and 2007, the Company examined the recoverability of a note receivable from the
City of Alameda California, and determined the carrying value of that investment
is not impaired. This was primarily a qualitative assessment of
collecting amounts due pursuant to the note agreement’s contract
provisions. Based on that review, the Company believes collection is
probable. However, actual amounts realized could differ from recorded
amounts.
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
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 18 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 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 2008, 2007, and 2006 and therefore resulted in no
impairment. Goodwill related to the Nonutility Group is also tested
using market comparable data, if readily available, 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 2008, 2007, and 2006, 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 has historically measured its obligations annually
on September 30. However, in 2008, the Company measured these
obligations on December 31 in accordance with SFAS 158. The Company
used the following weighted average assumptions to develop 2008 periodic benefit
cost: a discount rate of 6.25 percent, an expected return on plan
assets of 8.25 percent, a rate of compensation increase of 3.75 percent, and an
inflation assumption of 3.5 percent. In 2008, the Company increased
the discount rate from 5.85 percent, which was used to measure 2007 periodic
cost due to an increase in benchmark interest rates. Due to the
recent and significant decline in asset values, retirement plan costs are
expected to be higher in 2009 and in subsequent years. Management
currently estimates a pension and postretirement cost of approximately $14 to
$16 million in 2009 depending on funding levels, compared to approximately $11
million in 2008. Future changes in health care costs, work force
demographics, interest rates, asset values 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 used to estimate
2009 projected costs would generally increase periodic benefit cost by
approximately $1.7 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.
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, 2008 approximated $183 million and $327 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, 2008 approximated $823 million and $192
million, respectively. Additionally, prior to Utility Holdings’
formation, Indiana Gas and SIGECO funded their operations separately, and
therefore, have long-term debt outstanding funded solely by their
operations.
The
Company’s common stock dividends are primarily funded by utility
operations. Nonutility operations have demonstrated 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, 2008, 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 of long-term capitalization at both December 31, 2008, and
2007. Long-term capitalization includes long-term debt, including
current maturities and debt subject to tender, as well as common shareholders’
equity.
As of
December 31, 2008, the Company was in compliance with all financial
covenants.
Available
Liquidity in Current Credit Conditions
As noted
below, in 2008 the Company completed permanent financing transactions, including
the issuance of $125 million in long-term debt; $125 million in common stock;
and an expansion of $120 million in the level of short-term borrowing capacity
for its nonutility operations. These transactions have increased the
level of unutilized short-term borrowing capacity. This unutilized
short-term debt capacity, when coupled with expected internally generated funds
and any additional long-term financings undertaken, should provide sufficient
liquidity over the next twelve to twenty four months to fund anticipated capital
expenditures, investments, and debt security redemptions.
Regarding
debt redemptions, they are insignificant in 2009, and $48 million is due in
2010. In addition, holders of certain debt instruments have the
one-time option to put them to the Company. Debt subject to these put
provisions total $80 million in 2009 and $10 million in 2010.
The
Company continues to develop plans to issue additional long-term debt over the
next twelve to twenty four months, assuming its A-/Baa1 investment grade credit
ratings will allow it to access the capital markets, as the need
arises. However, while debt markets have improved somewhat, such
long-term debt issued during this period could be more expensive than in recent
history. This permanent financing would reduce reliance on unutilized
short-term capacity.
Consolidated Short-Term
Borrowing Arrangements
At
December 31, 2008, the Company had $905 million of short-term borrowing
capacity, including $520 million for the Utility Group and $385 million for the
wholly owned Nonutility Group and corporate operations, of which approximately
$328 million was available for the Utility Group operations and approximately
$55 million was available for the wholly owned Nonutility Group and corporate
operations, as reduced for approximately $3 million in outstanding letters of
credit. Of the $520 million in Utility Group capacity, $515
million is available through November, 2010; and of the $385 million in
Nonutility capacity, $120 million is available through September, 2009 and $255
million is available through November, 2010.
Historically,
the Company has funded the short-term borrowing needs of Utility Holdings’
operations through the commercial paper market. In 2008, the
Company’s access to longer term commercial paper was significantly reduced as a
result of the continued turmoil and volatility in the financial markets.
As a result, the Company has met working capital requirements through a
combination of A2/P2 commercial paper issuances and draws on Utility
Holdings’ $515 million commercial paper back-up credit
facilities. In addition, the Company increased its cash
investments by approximately $75 million during the fourth quarter of
2008. These cash positions were liquidated in January 2009 based upon
improvements in the short-term debt and commercial paper
markets. Their liquidation resulted in an increase to the
available short-term debt capacity for the Utility Group by $40 million and for
the Nonutility Group by $35 million.
ProLiance Short-Term
Borrowing Arrangements
ProLiance,
a nonutility energy marketing affiliate of Vectren and Citizens, has its own
short-term borrowing capacity available through a syndicated credit
facility. The terms of the facility allow for $300 million of
capacity from April 1 through September 30, and $400 million during the October
1 through March 31 heating season. At December 31, 2008,
approximately $56 million was outstanding. This remaining unutilized
capacity, when coupled with internally generated funds, is expected to provide
sufficient liquidity to meet ProLiance's operational needs. The
facility expires June 2009, at which time, ProLiance anticipates having a new
credit facility in place to support its future working capital
requirements. Future working capital requirements may be less than
the level of the current credit line given the recent decline in natural gas
prices. The current facility is not guaranteed by Vectren or
Citizens.
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 $1.2
million in 2008 and $5.2 million in 2007. In 2009, new issuances
required to meet these various plan requirements are estimated to be
approximately $6 million.
Potential
Uses of Liquidity
Pension and Postretirement
Funding Obligations
The
Company’s consolidated financial statements as of December 31, 2008 reported
pension plan asset values of approximately $151 million, compared to asset
values as of December 31, 2007 of approximately $212 million, and since December
31, 2008, market values have remained volatile and have experienced further
declines. Asset values for qualified plans as of December 31, 2008
are approximately 61 percent of the projected benefit obligation. Management
currently estimates that the qualified pension plans may require Company
contributions of approximately $25 to $30 million in 2009 and a lesser level in
2010. During 2008, approximately $12 million in contributions
were made.
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, 2008, 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
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.”
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 2009 - 2013 are estimated as follows:
|
(In
millions)
|
2009
|
2010
|
2011
|
2012
|
2013
|
|||||||||||||||
|
Utility
Group
|
$ | 250 | $ | 265 | $ | 255 | $ | 270 | $ | 245 | ||||||||||
|
Nonutility
Group
|
105 | 105 | 60 | 55 | 60 | |||||||||||||||
|
Total
capital expenditures & investments
|
$ | 355 | $ | 370 | $ | 315 | $ | 325 | $ | 305 | ||||||||||
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2008:
|
(In
millions)
|
Total
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
|||||||||||||||||||||
|
Long-term
debt (1)
|
$ | 1,328.3 | $ | 0.4 | $ | 47.5 | $ | 250.0 | $ | 60.0 | $ | 105.0 | $ | 865.4 | ||||||||||||||
|
Short-term
debt
|
519.5 | 519.5 | - | - | - | - | - | |||||||||||||||||||||
|
Long-term
debt interest commitments
|
1,094.4 | 81.5 | 81.4 | 77.1 | 60.1 | 55.6 | 738.7 | |||||||||||||||||||||
|
Nonutility
commodity purchase commitments
|
76.1 | 55.3 | 5.2 | 5.2 | 5.2 | 5.2 | - | |||||||||||||||||||||
|
Plant
purchase commitments (2)
|
45.1 | 45.1 | - | - | - | - | - | |||||||||||||||||||||
|
Operating
leases
|
16.6 | 6.6 | 4.5 | 2.3 | 1.5 | 1.2 | 0.5 | |||||||||||||||||||||
|
Total
(3)
|
$ | 3080.0 | $ | 708.4 | $ | 138.6 | $ | 334.6 | $ | 126.8 | $ | 167.0 | $ | 1,604.6 | ||||||||||||||
|
(1)
|
Certain
long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions
allow holders the one-time option 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 2008 (in millions) is $80.0 in 2009, $10.0 in 2010, $30.0 in
2011, zero in 2012 and thereafter.
|
|
(2)
|
The
settlement period of these utility and nonutility plant obligations is
estimated.
|
|
(3)
|
The
Company has other long-term liabilities that total approximately $244
million. This amount is comprised of the
following: pension obligations $109 million, postretirement
obligations $64 million, deferred compensation and share-based
compensation $28 million, asset retirement obligations $27 million,
investment tax credits $7 million, environmental remediation $6 million,
and other obligations including unrecognized tax benefits totaling $3
million. Based on the nature of these items their expected
settlement dates 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.
Comparison of Historical
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 $423.2 million in 2008,
compared to $298.1 million in 2007 and $310.2 million in 2006.
In 2008
cash flow from operating activities increased $125.1 million compared to
2007. Higher levels of deferred taxes due primarily to federal
stimulus plans authorizing bonus depreciation on qualifying capital expenditures
increased cash flow approximately $52.6 million. Working capital
changes generated cash of $9.2 million in 2008 compared to cash used of $27.0
million in 2007. The increase in cash from working capital results
primarily from the permanent reduction of natural gas inventory associated with
VEDO’s exit of the merchant function, offset by growth in recoverable fuel
balances. The remaining increase in operating cash flow is primarily
due to the cash collection of previously deferred regulatory
assets.
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. 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, decreased approximately $15.0 million due to primarily to a $10.4
million special dividend from ProLiance in 2006. In 2007 the Company
also increased its pension contributions, which resulted in a decrease to
operating cash flow, compared to 2006. These decreases were partially
offset by the higher earnings in 2007 as well as increased deferred
taxes.
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.
Net cash
flow generated from financing activities were $51.8 million in
2008. The increased cash generated from financing activities during
2008 compared to 2007 is reflective of the impact of completed long-term
financing transactions, including the issuance of common stock and long term
debt. In 2007 compared to 2006, financing activities reflect
short-term and long-term debt proceeds and stock option proceeds offset by debt
payments and dividends.
In 2008,
Vectren settled an equity forward contract receiving proceeds of approximately
$124.9 million, and Utility Holdings issued $125 million of senior unsecured
securities and used those proceeds to refinance certain capital projects
originally financed with short-term borrowings. Also, during the
first quarter of 2008, the Company mitigated its exposure to auction rate debt
markets. In 2006, Utility Holdings issued $100 million of senior
unsecured securities and used those proceeds to retire higher coupon long-term
debt. These transactions are more fully described below.
Vectren
Capital Short Term Debt Issuance
On
September 11, 2008, Vectren Capital entered into a 364-day $120 million
credit agreement that was syndicated with 7 banks. The agreement provides
for revolving loans and letters of credit up to $120 million. Borrowings
under the agreement may be at a floating rate or a Eurodollar
rate. Current floating rate advances would be priced at the
greater of the Federal Funds Rate plus 0.5 percent or the Prime Rate.
Current Eurodollar advances, based on Vectren's current credit rating, would
expect to be priced at the appropriate LIBOR rate plus 0.65
percent.
Vectren
Common Stock Issuance
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 allowed
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.
On June
27, 2008, the Company physically settled the equity forward by delivering the
4.6 million shares, receiving proceeds of approximately $124.9 million.
The slight difference between the proceeds generated by the public offering and
those received by the Company were due to adjustments defined in the equity
forward agreement including: 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.
Vectren
transferred the proceeds to Utility Holdings, and Utility Holdings used the
proceeds to repay short-term debt obligations incurred primarily to fund its
capital expenditure program. The proceeds received were recorded as an
increase to Common
Stock in Common Shareholders’ Equity and are presented in the Statement
of Cash Flows as a financing activity.
Utility
Holdings 2008 Debt Issuance
In March
2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured
notes due April 1, 2039 (2039 Notes) at par. The 2039 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 2039
Notes have no sinking fund requirements, and interest payments are due
monthly. The notes may be called by Utility Holdings, in whole or in
part, at any time on or after April 1, 2013, at 100 percent of principal amount
plus accrued interest. During 2007, Utility Holdings entered into
several interest rate hedges with an $80 million notional
amount. Upon issuance of the notes, these instruments were settled
resulting in the payment of approximately $9.6 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 2039 Notes less settlement
of the hedging arrangements and payments of issuance costs amounted to
approximately $111.1 million.
Auction
Rate Securities
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt had a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate was to 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 (Ambac).
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax-exempt auction rate mode long-term debt, including the $17
million issued in December 2007, of its plans to convert that debt from its
current auction rate mode into a daily interest rate mode. In March
2008, the debt was tendered at 100 percent of the principal amount plus accrued
interest. During March 2008, SIGECO remarketed approximately $61.8
million of these instruments at interest rates that are fixed to maturity,
receiving proceeds, net of issuance costs, of approximately $60.0
million. The terms are $22.6 million at 5.15 percent due in 2023,
$22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due
in 2041. The remaining $41.3 million continues to be held in treasury
and is expected to be remarketed in 2009.
Utility Holdings 2006 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.
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. The note had a stated interest rate of
7.25 percent.
Other
Financing Transactions
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 was retired as
scheduled.
Long-Term
Debt Put and Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. Other than certain instruments that
can be put to the company upon the death of the holder (death puts), these put
or call provisions are not triggered by specific events, but are based upon
dates stated in the note agreements. During 2008, the Company repaid
approximately $1.6 million related to death puts. In 2007 and 2006,
no debt was put to the Company. Debt which may be put to the Company
for reasons other than a death during the years following 2008 (in millions) is
$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.
Investing Cash
Flow
Cash flow
required for investing activities was $402.4 million in 2008, $303.0 million in
2007, and $337.4 million in 2006. Capital expenditures are the
primary component of investing activities and totaled $391.0 million in 2008,
compared to $334.5 million in 2007 and $281.4 million in 2006. The
year ended December 31, 2008 includes increased capital expenditures for coal
mine development and for environmental compliance equipment, compared to
2007. Other investments in 2008 include minor acquisitions by Miller,
among other items. The year ended December 31, 2007 also includes
expenditures for environmental compliance equipment as well as increased
spending for electric transmission, a new gas line serving a Honda plant in the
Vectren North service territory, and coal mine development, compared to
2006.
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.
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.
|
|
·
|
Economic
conditions surrounding the current recession, which may be more prolonged
and more severe than cyclical downturns, including significantly lower
levels of economic activity; uncertainty regarding energy prices and the
capital and commodity markets; decreases in demand for natural gas,
electricity, coal, and other nonutility products and services; impacts on
both gas and electric large customers; lower residential and commercial
customer counts; higher operating expenses; and further reductions in the
value of certain nonutility real estate and other legacy
investments.
|
|
·
|
Increased
natural gas and coal 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.
|
|
·
|
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.
|
|
·
|
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 Company’s coal mining, gas marketing,
and energy infrastructure
strategies.
|
|
·
|
Factors
affecting coal mining operations including MSHA guidelines and
interpretations of those guidelines; geologic, equipment, and operational
risks; sales contract negotiations and interpretations; supplier and
contract miner performance; the availability of key equipment, contract
miners and commodities; availability of transportation; and the ability to
access/replace coal reserves.
|
|
·
|
Employee
or contractor workforce factors including changes in key executives,
collective bargaining agreements with union employees, aging workforce
issues, work stoppages, or pandemic
illness.
|
|
·
|
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 or additions to federal, state or local legislative
requirements, such as changes in or additions to 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, coal and purchased
power 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 those
authorizing lost margin recovery, other innovative rate designs, 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 manages 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 undertake strategies to optimize
electric generating capacity beyond that needed for native load. In
recent years, the primary strategy involves the sale of excess generation into
the MISO Day Ahead and Real-time markets. As part of these
strategies, the Company may also from time to time 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
occasionally offsetting forward purchase contracts. The Company
accounts for any energy 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, 2008 and
2007.
For
retail sales of electricity, the Company receives the majority of its NOx and
SO2
allowances at zero cost through an allocation process. Based
on arrangements with regulators, wholesale operations can purchase allowances
from retail operations at current market values, the value of which is
distributed back to retail customers through a MISO cost recovery tracking
mechanism. Wholesale operations are therefore at risk for the cost of
allowances, which for the recent past have been volatile. The Company
manages this risk by purchasing allowances from retail operations and other
third parties in advance of usage creating an intangible asset. In
the past, the Company has also used derivative financial instruments to hedge
this risk, but no such derivative instruments were outstanding at December 31,
2008 or 2007.
Other
Operations
Other
commodity-related operations are exposed to commodity price risk associated with
fluctuating commodity prices including natural gas and coal. Other
commodity-related operations include 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 2008 and 2007, the weighted average
combined borrowings under these arrangements approximated $412 million and $495
million, respectively. At December 31, 2008 and 2007, combined
borrowings under these arrangements were $519 million and $660 million,
respectively. Based upon average borrowing rates under these
facilities during the years ended December 31, 2008 and 2007, an increase of 100
basis points (one percentage point) in the rates would have increased interest
expense by $4.1 million and $4.9 million, respectively.
Other
Risks
By using
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 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 based on historical
experience.
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 control 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,
2008. Management certified this in its Sarbanes Oxley Section 302
certifications, which are attached as exhibits to this 2008 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, 2008 and 2007, 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, 2008. Our
audits also included the financial statement schedule listed 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, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2008, 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.
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, 2008,
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 18, 2009
expressed an unqualified opinion on the
Company’s internal control over financial reporting.
/s/
Deloitte & Touche LLP
Indianapolis,
Indiana
February
18, 2009
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, 2008, 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 opinion.
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, 2008, 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, 2008 of the
Company and our report dated February 18, 2009 expressed an unqualified opinion
on those financial statements and financial statement
schedule.
/s/
Deloitte & Touche LLP
Indianapolis,
Indiana
February
18, 2009
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
|
|
CONSOLIDATED
BALANCE SHEETS
|
(In
millions)
|
At December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
& cash equivalents
|
$ | 93.2 | $ | 20.6 | ||||
|
Accounts
receivable - less reserves of $5.6 &
|
||||||||
|
$3.7,
respectively
|
226.7 | 189.4 | ||||||
|
Accrued
unbilled revenues
|
197.0 | 168.2 | ||||||
|
Inventories
|
131.0 | 160.9 | ||||||
|
Recoverable
fuel & natural gas costs
|
3.1 | - | ||||||
|
Prepayments
& other current assets
|
124.6 | 160.5 | ||||||
|
Total
current assets
|
775.6 | 699.6 | ||||||
|
Utility
Plant
|
||||||||
|
Original
cost
|
4,335.3 | 4,062.9 | ||||||
|
Less: accumulated
depreciation & amortization
|
1,615.0 | 1,523.2 | ||||||
|
Net
utility plant
|
2,720.3 | 2,539.7 | ||||||
|
Investments
in unconsolidated affiliates
|
179.1 | 208.8 | ||||||
|
Other
utility & corporate investments
|
25.7 | 26.3 | ||||||
|
Other
nonutility investments
|
45.9 | 50.7 | ||||||
|
Nonutility
property - net
|
390.2 | 320.3 | ||||||
|
Goodwill
- net
|
240.2 | 238.0 | ||||||
|
Regulatory
assets
|
216.7 | 175.3 | ||||||
|
Other
assets
|
39.2 | 37.7 | ||||||
|
TOTAL
ASSETS
|
$ | 4,632.9 | $ | 4,296.4 | ||||
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,
|
||||||||
|
2008
|
2007
|
|||||||
|
LIABILITIES & SHAREHOLDERS'
EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable
|
$ | 266.1 | $ | 187.4 | ||||
|
Accounts
payable to affiliated companies
|
75.2 | 83.7 | ||||||
|
Refundable
fuel & natural gas costs
|
4.1 | 27.2 | ||||||
|
Accrued
liabilities
|
175.0 | 171.8 | ||||||
|
Short-term
borrowings
|
519.5 | 557.0 | ||||||
|
Current
maturities of long-term debt
|
0.4 | 0.3 | ||||||
|
Long-term
debt subject to tender
|
80.0 | - | ||||||
|
Total
current liabilities
|
1,120.3 | 1,027.4 | ||||||
|
Long-term
Debt - Net of Current Maturities &
|
||||||||
|
Debt
Subject to Tender
|
1,247.9 | 1,245.4 | ||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||
|
Deferred
income taxes
|
353.4 | 318.1 | ||||||
|
Regulatory
liabilities
|
315.1 | 307.2 | ||||||
|
Deferred
credits & other liabilities
|
244.2 | 164.2 | ||||||
|
Total
deferred credits & other liabilities
|
912.7 | 789.5 | ||||||
|
Minority
Interest in Subsidiary
|
0.4 | 0.4 | ||||||
|
Commitments
& Contingencies (Notes 3, 14-16)
|
||||||||
|
Common
Shareholders' Equity
|
||||||||
|
Common
stock (no par value) – issued & outstanding
|
||||||||
|
81.0
and 76.3, respectively
|
659.1 | 532.7 | ||||||
|
Retained
earnings
|
712.8 | 688.5 | ||||||
|
Accumulated
other comprehensive income/(loss)
|
(20.3 | ) | 12.5 | |||||
|
Total
common shareholders' equity
|
1,351.6 | 1,233.7 | ||||||
|
TOTAL
LIABILITIES & SHAREHOLDERS' EQUITY
|
$ | 4,632.9 | $ | 4,296.4 | ||||
|
|
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,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Electric
utility
|
524.2 | 487.9 | 422.2 | |||||||||
|
Nonutility
revenues
|
527.8 | 524.6 | 386.9 | |||||||||
|
Total
operating revenues
|
2,484.7 | 2,281.9 | 2,041.6 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
983.1 | 847.2 | 841.5 | |||||||||
|
Cost
of fuel & purchased power
|
182.9 | 174.8 | 151.5 | |||||||||
|
Cost
of nonutility revenues
|
282.2 | 287.7 | 248.7 | |||||||||
|
Other
operating
|
506.3 | 456.9 | 341.8 | |||||||||
|
Depreciation
& amortization
|
192.3 | 184.8 | 172.3 | |||||||||
|
Taxes
other than income taxes
|
74.5 | 70.0 | 65.3 | |||||||||
|
Total
operating expenses
|
2,221.3 | 2,021.4 | 1,821.1 | |||||||||
|
OPERATING
INCOME
|
263.4 | 260.5 | 220.5 | |||||||||
|
OTHER
INCOME
|
||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
37.4 | 22.9 | 17.0 | |||||||||
|
Other
– net
|
2.1 | 36.8 | (2.7 | ) | ||||||||
|
Total
other income
|
39.5 | 59.7 | 14.3 | |||||||||
|
Interest
expense
|
97.8 | 101.0 | 95.6 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
205.1 | 219.2 | 139.2 | |||||||||
|
Income
taxes
|
76.1 | 76.0 | 30.3 | |||||||||
|
Minority
interest
|
- | 0.1 | 0.1 | |||||||||
|
NET
INCOME
|
$ | 129.0 | $ | 143.1 | $ | 108.8 | ||||||
|
AVERAGE
COMMON SHARES OUTSTANDING
|
78.3 | 75.9 | 75.7 | |||||||||
|
DILUTED
COMMON SHARES OUTSTANDING
|
78.9 | 76.6 | 76.2 | |||||||||
|
EARNINGS
PER SHARE OF COMMON STOCK:
|
||||||||||||
|
BASIC
|
$ | 1.65 | $ | 1.89 | $ | 1.44 | ||||||
|
DILUTED
|
$ | 1.63 | $ | 1.87 | $ | 1.43 | ||||||
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,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net
income
|
$ | 129.0 | $ | 143.1 | $ | 108.8 | ||||||
|
Adjustments
to reconcile net income to cash from operating activities:
|
||||||||||||
|
Depreciation
& amortization
|
192.3 | 184.8 | 172.3 | |||||||||
|
Deferred
income taxes & investment tax credits
|
79.6 | 27.0 | 1.4 | |||||||||
|
Equity
in earnings of unconsolidated affiliates
|
(37.4 | ) | (22.9 | ) | (17.0 | ) | ||||||
|
Provision
for uncollectible accounts
|
16.9 | 16.6 | 15.3 | |||||||||
|
Expense
portion of pension & postretirement benefit cost
|
7.8 | 9.8 | 10.7 | |||||||||
|
Other
non-cash charges - net
|
25.4 | 4.8 | 11.4 | |||||||||
|
Changes
in working capital accounts:
|
||||||||||||
|
Accounts
receivable & accrued unbilled revenue
|
(83.0 | ) | (29.1 | ) | 108.9 | |||||||
|
Inventories
|
26.4 | 2.6 | (17.6 | ) | ||||||||
|
Recoverable/refundable
fuel & natural gas costs
|
(26.2 | ) | (6.3 | ) | 41.3 | |||||||
|
Prepayments
& other current assets
|
9.8 | (3.7 | ) | (21.2 | ) | |||||||
|
Accounts
payable, including to affiliated companies
|
65.7 | 4.9 | (71.6 | ) | ||||||||
|
Accrued
liabilities
|
16.5 | 4.6 | (23.2 | ) | ||||||||
|
Unconsolidated
affiliate dividends
|
15.5 | 20.8 | 35.8 | |||||||||
|
Changes
in noncurrent assets
|
19.6 | (21.4 | ) | (25.8 | ) | |||||||
|
Changes
in noncurrent liabilities
|
(34.7 | ) | (37.5 | ) | (19.3 | ) | ||||||
|
Net
cash flows from operating activities
|
423.2 | 298.1 | 310.2 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Common
stock - net of issuance costs
|
124.9 | - | - | |||||||||
|
Long-term
debt - net of issuance costs
|
171.4 | 16.4 | 92.8 | |||||||||
|
Stock
option exercises & other stock plans
|
0.8 | 5.2 | - | |||||||||
|
Requirements
for:
|
||||||||||||
|
Dividends
on common stock
|
(102.6 | ) | (96.4 | ) | (93.1 | ) | ||||||
|
Retirement
of long-term debt
|
(104.9 | ) | (23.9 | ) | (124.4 | ) | ||||||
|
Other
activity
|
- | (0.8 | ) | (0.6 | ) | |||||||
|
Net
change in short-term borrowings
|
(37.8 | ) | 92.2 | 164.9 | ||||||||
|
Net
cash flows from financing activities
|
51.8 | (7.3 | ) | 39.6 | ||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Unconsolidated
affiliate distributions
|
0.2 | 12.7 | 2.0 | |||||||||
|
Other
collections
|
6.4 | 38.0 | 3.4 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(391.0 | ) | (334.5 | ) | (281.4 | ) | ||||||
|
Unconsolidated
affiliate investments
|
(0.6 | ) | (17.5 | ) | (16.7 | ) | ||||||
|
Other
investments
|
(17.4 | ) | (1.7 | ) | (44.7 | ) | ||||||
|
Net
cash flows from investing activities
|
(402.4 | ) | (303.0 | ) | (337.4 | ) | ||||||
|
Net
change in cash & cash equivalents
|
72.6 | (12.2 | ) | 12.4 | ||||||||
|
Cash
& cash equivalents at beginning of period
|
20.6 | 32.8 | 20.4 | |||||||||
|
Cash
& cash equivalents at end of period
|
$ | 93.2 | $ | 20.6 | $ | 32.8 | ||||||
|
Cash
paid during the year for:
|
||||||||||||
|
Interest
|
$ | 92.6 | $ | 97.3 | $ | 92.9 | ||||||
|
Income
taxes
|
(3.5 | ) | 43.7 | 36.3 | ||||||||
The accompanying notes are an integral
part of these consolidated financial statements.
-60-
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, 2006
|
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 million in tax
|
6.8 | 6.8 | ||||||||||||||||||
|
Total
comprehensive income
|
150.5 | |||||||||||||||||||
|
Adoption
of FIN 48
|
(0.1 | ) | (0.1 | ) | ||||||||||||||||
|
Common
stock:
|
||||||||||||||||||||
|
Issuance: option
exercises & dividend reinvestment plan
|
0.2 | 5.2 | 5.2 | |||||||||||||||||
|
Dividends
($1.27 per share)
|
(96.4 | ) | (96.4 | ) | ||||||||||||||||
|
Other
|
2.0 | (1.7 | ) | 0.3 | ||||||||||||||||
|
Balance
at December 31, 2007
|
76.3 | 532.7 | 688.5 | 12.5 | 1,233.7 | |||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net
income
|
129.0 | 129.0 | ||||||||||||||||||
|
SFAS
158 funded status adjustment - net of $1.7 million in tax
|
(2.4 | ) | (2.4 | ) | ||||||||||||||||
|
Cash
flow hedges
|
||||||||||||||||||||
|
reclassifications
to net income- net of $0.2 million in tax
|
(0.2 | ) | (0.2 | ) | ||||||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||||||
|
affiliates
- net of $20.0 million in tax
|
(30.2 | ) | (30.2 | ) | ||||||||||||||||
|
Total
comprehensive income
|
96.2 | |||||||||||||||||||
|
SFAS
158 measurement date adjustment- net of $1.1 million in
tax
|
(1.6 | ) | (1.6 | ) | ||||||||||||||||
|
Common
stock:
|
||||||||||||||||||||
|
Issuance: settlement
of equity forward
|
4.6 | 124.9 | 124.9 | |||||||||||||||||
|
Issuance: option
exercises & dividend reinvestment plan
|
0.1 | 1.2 | 1.2 | |||||||||||||||||
|
Dividends
($1.31 per share)
|
(102.6 | ) | (102.6 | ) | ||||||||||||||||
|
Other
|
- | 0.3 | (0.5 | ) | (0.2 | ) | ||||||||||||||
|
Balance
at December 31, 2008
|
81.0 | $ | 659.1 | $ | 712.8 | $ | (20.3 | ) | $ | 1,351.6 | ||||||||||
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 111,000
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 317,000 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 legacy businesses that
have invested in energy-related opportunities and services, real estate, and
leveraged leases, among other investments. 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, and infrastructure
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.
|
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.
|
Revenues
|
Most
revenues are recorded as products and services are delivered to customers.
However, some nonutility revenues are recognized using the percentage of
completion method with such percentage based on project cost. 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.
|
D.
|
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 $45.0 million in 2008, $41.8
million in 2007, and $39.7 million in 2006. Expense associated with
excise and utility receipts taxes are recorded as a component of Taxes other than income
taxes.
|
E.
|
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.
|
F.
|
Inventories
|
Inventories consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Gas
in storage – at average cost
|
$ | 40.4 | $ | 76.8 | ||||
|
Gas
in storage – at LIFO cost
|
22.2 | 16.7 | ||||||
|
Total
Gas in storage
|
62.6 | 93.5 | ||||||
|
Materials
& supplies
|
33.4 | 33.0 | ||||||
|
Fuel
(coal & oil) for electric generation
|
31.7 | 30.6 | ||||||
|
Other
|
3.3 | 3.8 | ||||||
|
Total
inventories
|
$ | 131.0 | $ | 160.9 | ||||
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, 2008, and 2007,
by approximately $35 million and $73 million, respectively. Gas in
storage of the Indiana regulated operations is stated at LIFO. All
other inventories are carried at average
cost.
|
G.
|
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)
|
2008
|
2007
|
||||||||||||||
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|||||||||||||
|
Gas
utility plant
|
$ | 2,157.6 | 3.5 | % | $ | 2,077.5 | 3.6 | % | ||||||||
|
Electric
utility plant
|
1,884.3 | 3.3 | % | 1,815.8 | 3.3 | % | ||||||||||
|
Common
utility plant
|
47.9 | 2.9 | % | 45.5 | 2.8 | % | ||||||||||
|
Construction
work in progress
|
245.5 | - | 124.1 | - | ||||||||||||
|
Total
original cost
|
$ | 4,335.3 | $ | 4,062.9 | ||||||||||||
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, 2008 is $63.5 million with
accumulated depreciation totaling $48.9 million. The construction
work-in-progress balance associated with SIGECO’s ownership interest totaled
$111.5 million at December 31, 2008. 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.
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.
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:Nonutility property, net of
accumulated depreciation and amortization follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
AFUDC
– borrowed funds
|
$ | 2.2 | $ | 3.5 | $ | 2.6 | ||||||
|
AFUDC
– equity funds
|
0.3 | 0.5 | 1.5 | |||||||||
|
Total
AFUDC
|
$ | 2.5 | $ | 4.0 | $ | 4.1 | ||||||
|
H.
|
Nonutility
Property
|
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Computer
hardware & software
|
$ | 129.6 | $ | 117.0 | ||||
|
Land
& buildings
|
93.9 | 76.2 | ||||||
|
Coal
mine development costs & equipment
|
109.1 | 71.3 | ||||||
|
Vehicles
& equipment
|
41.7 | 35.0 | ||||||
|
All
other
|
15.9 | 20.8 | ||||||
|
Nonutility
property - net
|
$ | 390.2 | $ | 320.3 | ||||
The
depreciation of nonutility property is charged against income over its estimated
useful life, 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 $281.6 million and $258.7
million as of December 31, 2008, and 2007, respectively. For the
years ended December 31, 2008, 2007, and 2006, the Company capitalized interest
totaling $3.7 million, $2.3 million, and $1.2 million, respectively, on
nonutility plant construction projects.
|
I.
|
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 19). 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)
|
2008
|
2007
|
||||||
|
ProLiance
Holdings, LLC
|
$ | 153.1 | $ | 178.6 | ||||
|
Haddington
Energy Partnerships
|
13.9 | 13.8 | ||||||
|
Other
partnerships & corporations
|
12.1 | 16.4 | ||||||
|
Total
investments in unconsolidated affiliates
|
$ | 179.1 | $ | 208.8 | ||||
|
J.
|
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, 2008, 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 $35.2 million is attributable to the
Nonutility Group.
|
K.
|
Intangible
Assets
|
Intangible
assets consist of the following:
|
(In
millions)
|
At
December 31,
|
|||||||||||||||
|
2008
|
2007
|
|||||||||||||||
|
Amortizing
|
Non-amortizing
|
Amortizing
|
Non-amortizing
|
|||||||||||||
|
Customer-related
assets
|
$ | 8.9 | $ | - | $ | 8.9 | $ | - | ||||||||
|
Market-related
assets
|
- | 7.0 | 0.1 | 7.0 | ||||||||||||
|
Intangible
assets, net
|
$ | 8.9 | $ | 7.0 | $ | 9.0 | $ | 7.0 | ||||||||
As of
December 31, 2008, the weighted average remaining life for amortizing
customer-related assets and all amortizing intangibles is 23
years. These amortizing intangible assets have no significant
residual values. Intangible assets are presented net of accumulated
amortization totaling $2.6 million for customer-related assets and $0.2 million
for market-related assets at December 31, 2008 and $2.0 million for
customer-related assets and $0.2 million for market-related assets at December
31, 2007. In 2008, 2007, and 2006, amortization associated with
intangible assets was $0.6 million, $0.7 million and $0.5 million,
respectively. Amortization should approximate that incurred in 2008
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 $1.6 million and $2.6 million at December 31, 2008 and 2007,
respectively. The value of the emission allowances are recognized as
they are consumed or sold on the open market.
|
L.
|
Regulation
|
Retail
public utility operations affecting Indiana customers are subject to regulation
by the IURC, and retail public utility operations affecting Ohio customers are
subject to regulation by the PUCO. The Company’s accounting policies
give recognition to the rate-making and accounting practices of these agencies
and to accounting principles generally accepted in the United States, including
the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation” (SFAS 71).
Refundable
or Recoverable Gas Costs and Cost of Fuel & Purchased Power
All
metered gas rates contain a gas cost adjustment clause that allows the Company
to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel. The net
energy cost of purchased power, subject to a variable benchmark based on NYMEX
natural gas prices, is also recovered through regulatory
proceedings. The Company records any under-or-over-recovery resulting
from gas and fuel adjustment clauses each month in revenues. A
corresponding asset or liability is recorded until the under or over-recovery is
billed or refunded to utility customers. The cost of gas sold is
charged to operating expense as delivered to customers, and the cost of fuel for
electric generation is charged to operating expense when consumed.
Regulatory
Assets and Liabilities
Regulatory
assets represent probable future revenues associated with certain incurred
costs, which will be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable expenditures by
the Company for removal costs or future reductions in revenues associated with
amounts that are to be credited to customers through the ratemaking
process. The Company assesses the recoverability of costs recognized
as regulatory assets and liabilities and the ability to continue to account for
its activities based on the criteria set forth in SFAS 71. Based on
current regulation, the Company believes such accounting is
appropriate. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be
required to determine any impairment to the carrying value of its utility plant
and other regulated assets.
Regulatory Assets consist of
the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Future
amounts recoverable from ratepayers related to:
|
||||||||
|
Benefit
obligations
|
$ | 101.0 | $ | 23.6 | ||||
|
Income
taxes- transition to SFAS 109
|
(0.7 | ) | (0.9 | ) | ||||
|
Income
taxes- deferred income taxes
|
12.1 | 14.9 | ||||||
|
Interest
rate derivatives
|
- | 8.9 | ||||||
|
Asset
retirement obligations & other
|
8.5 | 10.9 | ||||||
| 120.9 | 57.4 | |||||||
|
Amounts
deferred for future recovery related to:
|
||||||||
|
Cost
recovery riders & other
|
1.7 | 1.9 | ||||||
| 1.7 | 1.9 | |||||||
|
Amounts
currently recovered in customer rates related to:
|
||||||||
|
Demand
side management programs
|
21.5 | 27.6 | ||||||
|
Unamortized
debt issue costs & hedging proceeds
|
38.4 | 25.0 | ||||||
|
Indiana
authorized trackers
|
13.8 | 42.3 | ||||||
|
Ohio
authorized trackers
|
11.6 | 10.4 | ||||||
|
Premiums
paid to reacquire debt & other
|
8.8 | 10.7 | ||||||
| 94.1 | 116.0 | |||||||
|
Total
regulatory assets
|
$ | 216.7 | $ | 175.3 | ||||
Of the
$94.1 million currently being recovered in customer rates charged to customers,
$21.5 million is earning a return. The weighted average recovery
period of regulatory assets currently being recovered is 13
years. The Company has rate orders for all deferred costs not yet in
rates and therefore believes that future recovery is probable.
Regulatory
Liabilities
At
December 31, 2008 and 2007, the Company has approximately $315.1 million and
$307.2 million, respectively, in regulatory liabilities. Of these
amounts, $292.4 million and $288.3 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).
|
M.
|
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 $27.5 million and $18.8 million at December 31, 2008
and 2007, respectively. ARO’s included in Accrued liabilities total
$7.2 million and $9.5 million at December 31, 2008 and 2007,
respectively. During 2008, the Company recorded accretion of $1.1
million and increases in estimates, net of cash payments of $5.2
million. During 2007, the Company recorded accretion of $1.2 million
and increases in estimates, net of cash payments of $6.3 million.
|
N.
|
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.
|
O.
|
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:
|
2006
|
2007
|
2008
|
||||||||||||||||||||||||||
|
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
|
$ | (0.5 | ) | $ | 10.7 | $ | 10.2 | 11.0 | $ | 21.2 | $ | (50.2 | ) | $ | (29.0 | ) | ||||||||||||
|
Pension
& other benefit costs
|
(29.0 | ) | 26.5 | (2.5 | ) | 1.2 | (1.3 | ) | (4.0 | ) | (5.3 | ) | ||||||||||||||||
|
Cash
flow hedges
|
6.7 | (6.0 | ) | 0.7 | (0.1 | ) | 0.6 | (0.5 | ) | 0.1 | ||||||||||||||||||
|
Deferred
income taxes
|
9.2 | (12.5 | ) | (3.3 | ) | (4.7 | ) | (8.0 | ) | 21.9 | 13.9 | |||||||||||||||||
|
Accumulated
other comprehensive income (loss)
|
$ | (13.6 | ) | $ | 18.7 | $ | 5.1 | $ | 7.4 | $ | 12.5 | $ | (32.8 | ) | $ | (20.3 | ) | |||||||||||
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. (See Note 3 for more
information on ProLiance.)
|
P.
|
Other
Significant Policies
|
Included
elsewhere in these Notes are significant accounting policies related to income
taxes (Note 8), pensions and postretirement benefits (Note 9), earnings per
share (Note 12), share based compensation (Note 13), and derivatives (Note
17).
|
3.
|
Investments
in ProLiance Holdings, LLC
|
ProLiance
Holdings, LLC (ProLiance), a nonutility energy marketing
affiliate of Vectren and Citizens Energy Group (Citizens), 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’
utilities. 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
2008, 2007, and 2006.
Summarized Financial
Information
|
Year
Ended December 31,
|
||||||||||||
|
(in
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Summarized
Statement of Income information:
|
||||||||||||
|
Revenues
|
$ | 2,883.6 | $ | 2,267.1 | $ | 2,505.5 | ||||||
|
Operating
income
|
63.7 | 61.5 | 55.0 | |||||||||
|
ProLiance's
earnings
|
64.7 | 67.2 | 57.9 | |||||||||
|
As
of December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Summarized
balance sheet information:
|
||||||||
|
Current
assets
|
$ | 661.5 | $ | 684.3 | ||||
|
Noncurrent
assets
|
104.2 | 45.2 | ||||||
|
Current
liabilities
|
514.0 | 436.9 | ||||||
|
Noncurrent
liabilities
|
3.6 | 4.3 | ||||||
|
Equity
|
248.1 | 288.3 | ||||||
Vectren
records its 61 percent share of ProLiance’s earnings after income taxes and an
interest expense
allocation.
Transactions with
ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2008, 2007, and 2006, totaled $940.1 million, $792.4 million, and
$777.0 million, respectively. Amounts owed to ProLiance at December
31, 2008, and 2007, for those purchases were $75.1 million and $81.5 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) in October 2007
possible non-compliance with the FERC’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 believes that it has adequately reserved for
this matter. Although the outcome of any legal or regulatory proceedings
resulting from these matters cannot be predicted, the final resolution of these
matters is not expected to have a material impact on the Company’s consolidated
operating results, financial position or cash flows.
Investment in Liberty Gas
Storage
Liberty
Gas Storage, LLC (Liberty) is a joint venture between a subsidiary of ProLiance
and a subsidiary of Sempra Energy (SE). ProLiance is the minority
member with a 25 percent interest, which it accounts for using the equity
method. Liberty holds a long-term lease of storage and mineral rights
associated with existing salt dome storage caverns in southern Louisiana, near
Sulphur, Louisiana. Liberty also owns a second site near Hackberry,
Louisiana with three additional existing salt dome storage
caverns. The members anticipated it would provide high deliverability
storage services via the salt dome caverns at both locations and, once developed
under current plans, there would be approximately 35 billion cubic feet of
working gas capacity at the two sites. ProLiance has a long
term contract for approximately 5 Bcf of working gas capacity. The total
project investment at the Sulphur site through December 31, 2008 is
approximately $200 million. ProLiance’s portion of the investment is
estimated at approximately $50 million.
On
October 27, 2008, SE confirmed to ProLiance that the completion of this phase of
Liberty’s development at the Sulphur site has been delayed by subsurface and
well-completion problems. Corrective measures are ongoing and
should they prove to be unsuccessful, the salt-cavern facility may not go into
service, or may have reduced capacity when placed in service. ProLiance
has tested its investment in Liberty for impairment assuming the corrective
measures currently being deployed are successful and has determined that its
investment is not impaired at December 31, 2008. However, the success of
these corrective measures may not be known until later in 2009. Based on
information received from SE concerning the maximum estimated possible exposure,
ProLiance estimates that a maximum of $35 million of its total investment would
be at risk (the Company’s proportionate share of the investment would be $21
million). The
Company believes that such a charge, should it occur, would not have a material
adverse effect on either the Company’s or ProLiance’s financial position, cash
flows, or liquidity, but it could be material to net income in any one
accounting period. Further, it is not expected that the delay in
Liberty’s development will impact ProLiance’s ability to meet the needs of its
customers.
ProLiance Lawsuit Settlement
in 2006
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. As an equity investor in ProLiance, Vectren
recorded its share of these charges which totaled $6.6 million after tax in
2006.
Undistributed
Earnings
As of
December 31, 2008, undistributed earnings of unconsolidated affiliates
approximated $162 million and are primarily comprised of the undistributed
earnings of ProLiance.
|
4.
|
Nonutility
Real Estate and Other Legacy
Holdings
|
Within
the Nonutility business segment, there are legacy investments involved in
energy-related infrastructure and services, real estate, leveraged leases, and
other ventures. As of December 31, 2008, total remaining legacy
investments included in the Other Businesses portfolio total $71.8
million. Further separation of that investment by type of investment
follows:
|
December
31, 2008
|
||||||||||||
|
Value
Included In
|
||||||||||||
|
(in
millions)
|
Remaining
Carrying Value
|
Other
Nonutility Investments
|
Investments
in Unconsolidated Affiliates
|
|||||||||
|
Commercial
Real Estate Investments
|
$ | 21.0 | $ | 21.0 | $ | - | ||||||
|
Leveraged
Leases
|
17.3 | 17.3 | - | |||||||||
|
Haddington
Energy Partnerships
|
14.3 | 0.4 | 13.9 | |||||||||
|
Affordable
Housing Projects
|
9.6 | 0.1 | 9.5 | |||||||||
|
Other
investments
|
9.6 | 7.1 | 2.5 | |||||||||
| $ | 71.8 | $ | 45.9 | $ | 25.9 | |||||||
Commercial Real Estate
Charge
The
current economic recession has impacted the value of commercial real estate
investments within this portfolio, and the prospect for recovery of that value
has diminished. During 2008, the Company assessed its commercial real
estate investments for impairment and identified the need to reduce their
carrying values. That assessment was conducted using SFAS No. 114,
“Accounting by Creditors for Impairment of a Loan”; APB 18, “The Equity Method
of Accounting for Investments in Common Stock”; and SFAS No. 144, “Accounting
for the Impairment or Disposal of Long-Lived Assets”; and their related
amendments and interpretations. The impairment charge totaled $10.0
million. Of the $10.0 million charge $5.2 million is included in
Other-net and $4.8
million is included in Other
operating expenses.
Notes
Receivable
Of the
$45.9 million in Other
nonutility investments identified above, notes receivable, inclusive of
any accrued interest, and net of impairment reserves totaled $16.7
million. As of December 31, 2007, comparable amounts were $21.5
million. The impairment reserve as of December 31, 2008 totaled $6.3
million and as of December 31, 2007 totaled $1.7 million. The change
in the reserve during 2008 results primarily from the aforementioned impairment
charge. In 2007 and 2006, reserve activity was not
significant. As of December 31, 2008, substantially all notes
receivable are considered impaired loans. It is the Company’s policy
to recognize interest on the cash basis for impaired loans; however, such
interest income has been insignificant during the past three
years. Generally, second mortgages serve as collateral for
these notes.
Leveraged
Leases
The
Company is a lessor in leveraged lease agreements under which real estate or
equipment is leased to third parties. The total equipment and
facilities cost was approximately $45.2 million at December 31,
2008. 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 $54.0 million at December
31, 2008. At December 31, 2008, the Company’s $17.3 million leveraged
lease investment when netted against related deferred tax liabilities, was $2.2
million.
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). The Company has no further commitments to invest in either
Haddington I or II. As of December 31, 2008, 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,
2008, revenues, operating loss, and net loss were (in millions) zero, $(0.4),
and $(0.3), respectively. 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. As of December 31, 2008, investments, other assets, and
liabilities were (in millions) $32.0, $0.5, and $0.1,
respectively. As of December 31, 2007, investments, other assets, and
liabilities were (in millions) $31.3, $1.1, and zero, respectively.
Variable Interest
Entities
Some of
these legacy nonutility investments are partnership-like structures and are
variable interest entities as defined by FASB Interpretation 46(R),
“Consolidation of Variable Interest Entities.” The Company is either a limited
partner or 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,
2008, and 2007, totaled $9.5 million and $11.4 million, respectively, recorded
in Investments in
unconsolidated affiliates, and $10.1 million and $11.5 million,
respectively, recorded in Other
nonutility investments. The Company does not
consolidate any of these entities
|
5.
|
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 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. Partnership
operations since that date have been insignificant.
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 2005 – 2007 are still subject to IRS examination. However,
avenues remain where the IRS could challenge tax credits for the years prior to
2005. As a partner of Pace Carbon, Vectren has reflected
cumulative synfuel tax credits of approximately $101 million in its consolidated
results, of which approximately $45 million were generated since 2004. To
date, Vectren has been in a position to utilize all of the credits
generated.
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. Because
of high oil prices in 2007, only $6.0 million of the approximate $23.1 million
in tax credits generated were reflected as a reduction to the Company’s income
tax expense. In 2006 high oil prices also phased out 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.
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 and a loss of $4.7 million in
2006. 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 and a loss of $5.3 million in 2006.
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, operating loss, and net loss were (in millions) $471.1,
($158.8), and ($240.2), respectively. For the year ended December 31,
2006, revenues, operating loss, and net loss were (in millions) $389.7,
($175.5), and ($176.8), 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.
|
6.
|
Utilicom
Networks, LLC & Related Entities Disposition in
2006
|
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.
|
7.
|
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 increases in
Other operating expense
totaling $90.9 million in 2007 compared to 2006.
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,
fees paid to Reliant for locating and meter reading services as well as for
Miller’s construction-related services totaled $20.6 million. Amounts
charged are market based. Amounts owed to Reliant totaled less than
$0.1 million at December 31, 2007 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.
|
8.
|
Income
Taxes
|
Significant
components of the net deferred tax liability follow:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Noncurrent
deferred tax liabilities (assets):
|
||||||||
|
Depreciation
& cost recovery timing differences
|
$ | 372.6 | $ | 309.3 | ||||
|
Leveraged
leases
|
15.1 | 19.3 | ||||||
|
Regulatory
assets recoverable through future rates
|
27.8 | 25.3 | ||||||
|
Demand
side management programs
|
- | 7.9 | ||||||
|
Other
comprehensive income
|
(15.0 | ) | 7.2 | |||||
|
Alternative
minimum tax carryforward
|
- | (3.4 | ) | |||||
|
Employee
benefit obligations
|
(36.2 | ) | (34.5 | ) | ||||
|
Net
operating loss & other carryforwards
|
(2.1 | ) | (4.1 | ) | ||||
|
Regulatory
liabilities to be settled through future rates
|
(15.7 | ) | (10.4 | ) | ||||
|
Other
– net
|
6.9 | 1.5 | ||||||
|
Net
noncurrent deferred tax liability
|
353.4 | 318.1 | ||||||
|
Current
deferred tax (assets)/liabilities:
|
||||||||
|
Deferred
fuel costs-net
|
2.6 | (1.2 | ) | |||||
|
Demand
side management programs
|
8.8 | - | ||||||
|
Alternative
minimum tax carryforward
|
(11.2 | ) | (29.6 | ) | ||||
|
Other
– net
|
(8.4 | ) | 0.9 | |||||
|
Net
current deferred tax (asset)/liability
|
(8.2 | ) | (29.9 | ) | ||||
|
Net
deferred tax liability
|
$ | 345.2 | $ | 288.2 | ||||
At
December 31, 2008 and 2007, investment tax credits totaling $6.9 million and
$8.2 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, 2008, the
Company has alternative minimum tax carryforwards of $11.2 million, which do not
expire. In addition, the Company has $2.1 million in net operating
loss carryforwards that relate to the acquisition of Miller, which will expire
in 5 to 20 years.
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.
A
reconciliation of the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Statutory
rate:
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State
and local taxes-net of federal benefit
|
3.9 | 4.3 | 5.7 | |||||||||
|
Amortization of
investment tax credit
|
(0.6 | ) | (0.8 | ) | (1.4 | ) | ||||||
|
Depletion
|
(0.4 | ) | (0.7 | ) | (1.6 | ) | ||||||
|
Other
tax credits
|
(0.9 | ) | (0.2 | ) | (0.5 | ) | ||||||
|
Synfuel
tax credits
|
- | (3.0 | ) | (9.6 | ) | |||||||
|
Tax law
change
|
- | 0.2 | (2.5 | ) | ||||||||
|
Adjustment of
income tax accruals
|
- | - | (2.0 | ) | ||||||||
|
All
other-net
|
0.1 | (0.1 | ) | (1.3 | ) | |||||||
|
Effective tax
rate
|
37.1 | % | 34.7 | % | 21.8 | % | ||||||
The
components of income tax expense and utilization of investment tax credits
follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | (14.8 | ) | $ | 35.9 | $ | 18.2 | |||||
|
State
|
11.3 | 13.1 | 10.7 | |||||||||
|
Total
current taxes
|
(3.5 | ) | 49.0 | 28.9 | ||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
78.2 | 24.6 | 7.0 | |||||||||
|
State
|
2.7 | 4.1 | (3.6 | ) | ||||||||
|
Total
deferred taxes
|
80.9 | 28.7 | 3.4 | |||||||||
|
Amortization
of investment tax credits
|
(1.3 | ) | (1.7 | ) | (2.0 | ) | ||||||
|
Total
income tax expense
|
$ | 76.1 | $ | 76.0 | $ | 30.3 | ||||||
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.
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, 2005. 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. The
statutes of limitations for assessment of federal and Indiana income tax have
expired with respect to tax years through
2002.
Following
is a roll forward of the total amount of unrecognized tax benefits for the years
ended December 31, 2008 and 2007:
|
(in
millions)
|
2008
|
2007
|
||||||
|
Unrecognized
tax benefits at January 1
|
$ | 6.2 | $ | 11.6 | ||||
|
Gross
Increases - tax positions in prior periods
|
1.7 | 0.3 | ||||||
|
Gross
Decreases - tax positions in prior periods
|
(6.0 | ) | (7.4 | ) | ||||
|
Gross
Increases - current period tax positions
|
0.3 | 1.9 | ||||||
|
Gross
Decreases - current period tax positions
|
- | (0.2 | ) | |||||
|
Unrecognized
tax benefits at December 31
|
$ | 2.2 | $ | 6.2 | ||||
The
change in unrecognized tax benefits during 2008 totaled $4.0 million, almost
none of which impacted the effective rate. During 2007 the change in
unrecognized tax benefits totaled $5.4 million, of which $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, 2008 and 2007, was $0.5 million and $0.1 million, respectively.
As of
December 31, 2008, 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.
The Company recognized expense related to interest and penalties totaling of
less than $0.1 million in 2008 and approximately $0.5 million in
2007. During the year ended December 31, 2006, the Company recognized
expense related to interest and penalties of less than $1
million. The Company had approximately $0.8 million for the payment
of interest and penalties accrued as of December 31, 2008 and 2007.
The net
liability on the Consolidated Balance Sheet for unrecognized tax benefits
inclusive of interest, penalties and net of secondary impacts which are a
component of the Deferred
taxes and are benefits, totaled $0.8 million and $2.5 million,
respectively, at December 31, 2008 and 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.
|
9.
|
Retirement
Plans & Other Postretirement
Benefits
|
At
December 31, 2008, 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 a Voluntary Employee Beneficiary
Association (VEBA) Trust Agreement for the partial funding of postretirement
health benefits for retirees and their eligible dependents and beneficiaries in
one of the three plans. Annual VEBA funding is
discretionary. 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.”
SFAS 158
The
Company accounts for its pension and post-retirement obligations in accordance
with 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). Under SFAS 158, the Company recognizes 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 exceeds amounts previously recognized, the Company records a Regulatory asset for that
portion related to its cost-based and rate regulated utilities. To
the extent that excess liability does not relate to a cost-based rate-regulated
utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive
income.
SFAS 158
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. These measurement date provisions were
adopted on January 1, 2008. Prior to the adoption of SFAS 158, Vectren had a
September 30 measurement date. The effects of adopting SFAS 158 were
calculated using a measurement of plan assets and benefit obligations as of
September 30, 2007 and a 15-month projection of periodic cost to December 31,
2008. The Company recorded three months of that cost totaling $2.7
million, or $1.6 million after tax, to retained earnings on January 1,
2008. Related adjustments to Accumulated other comprehensive
income and Regulatory
assets were not material.
Net Periodic Benefit
Costs
A summary
of the components of net periodic benefit cost for the three years ended
December 31, 2008, follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
2008
|
2007
|
2006
|
||||||||||||||||||
|
Service
cost
|
$ | 6.1 | $ | 5.6 | $ | 6.0 | $ | 0.5 | $ | 0.5 | $ | 0.6 | ||||||||||||
|
Interest
cost
|
15.1 | 14.9 | 14.1 | 4.2 | 4.0 | 3.9 | ||||||||||||||||||
|
Expected
return on plan assets
|
(16.6 | ) | (14.3 | ) | (13.5 | ) | (0.5 | ) | (0.5 | ) | (0.6 | ) | ||||||||||||
|
Amortization
of prior service cost
|
1.7 | 1.7 | 1.8 | (0.8 | ) | (0.8 | ) | (0.8 | ) | |||||||||||||||
|
Amortization
of actuarial loss (gain)
|
0.1 | 1.5 | 2.4 | - | (0.1 | ) | - | |||||||||||||||||
|
Amortization
of transitional obligation
|
- | - | - | 1.1 | 1.1 | 1.1 | ||||||||||||||||||
|
Net
periodic benefit cost
|
$ | 6.4 | $ | 9.4 | $ | 10.8 | $ | 4.5 | $ | 4.2 | $ | 4.2 | ||||||||||||
A portion
of benefit costs are capitalized as Utility
plant. Costs capitalized in 2008, 2007, and 2006 approximated
$3.0 million, $3.9 million, and $4.3 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. For
the majority of the Company’s pension plans, 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 2008 periodic benefit
cost. For fiscal 2009, 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 2009, the discount rate will be consistent with 2008 at 6.25
percent.
The
weighted averages of significant assumptions used to determine net periodic
benefit costs follow:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
2008
|
2007
|
2006
|
||||||||||||||||||
|
Discount
rate
|
6.25 | % | 5.85 | % | 5.50 | % | 6.25 | % | 5.85 | % | 5.50 | % | ||||||||||||
|
Rate
of compensation increase
|
3.75 | % | 3.75 | % | 3.25 | % | 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 its 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.
Benefit
Obligations
A
reconciliation of the Company’s benefit obligations at December 31, 2008 and
2007, follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
|
Benefit
obligation, beginning of period
|
$ | 249.6 | $ | 255.4 | $ | 70.2 | $ | 69.5 | ||||||||
|
Service
cost – benefits earned during the period
|
7.7 | 5.6 | 0.7 | 0.5 | ||||||||||||
|
Interest
cost on projected benefit obligation
|
18.8 | 14.9 | 5.2 | 3.9 | ||||||||||||
|
Plan
participants' contributions
|
- | - | 2.8 | 1.3 | ||||||||||||
|
Plan
amendments
|
0.4 | - | - | - | ||||||||||||
|
Actuarial
loss (gain)
|
0.3 | (13.9 | ) | 2.5 | 1.5 | |||||||||||
|
Medicare
subsidy receipts
|
- | - | 0.7 | 0.2 | ||||||||||||
|
Benefits
paid
|
(16.2 | ) | (12.4 | ) | (9.8 | ) | (6.7 | ) | ||||||||
|
Benefit
obligation, end of period
|
$ | 260.6 | $ | 249.6 | $ | 72.3 | $ | 70.2 | ||||||||
The
accumulated benefit obligation for all defined benefit pension plans was $245.2
million and $231.9 million at December 31, 2008 and 2007,
respectively. Due to moving the measurement date from September 30 to
December 31, in accordance with SFAS 158, the 2008 roll forward of the projected
benefit obligation includes 15 months of activity.
The
benefit obligation as of December 31, 2008 and 2007 was calculated using the
following assumptions:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
Discount
rate
|
6.25 | % | 6.25 | % | 6.25 | % | 6.25 | % | ||||||||
|
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 | % | ||||||||||
Plan
Assets
A
reconciliation of the Company’s plan assets at December 31, 2008 and 2007
follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
|
Plan
assets at fair value, beginning of period
|
$ | 211.8 | $ | 185.0 | $ | 6.8 | $ | 6.8 | ||||||||
|
Actual
return on plan assets
|
(58.0 | ) | 22.3 | (1.4 | ) | 0.9 | ||||||||||
|
Employer
contributions
|
13.3 | 16.9 | 5.9 | 4.5 | ||||||||||||
|
Plan
participants' contributions
|
- | - | 2.8 | 1.3 | ||||||||||||
|
Benefits
paid
|
(16.2 | ) | (12.4 | ) | (9.8 | ) | (6.7 | ) | ||||||||
|
Fair
value of plan assets, end of period
|
$ | 150.9 | $ | 211.8 | $ | 4.3 | $ | 6.8 | ||||||||
Due to
moving the measurement date from September 30 to December 31, in accordance with
SFAS 158, the 2008 roll forward of plan assets includes 15 months of
activity.
The asset
allocation for the Company's pension and postretirement plans at the measurement
date for 2008 and 2007 by asset category follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
Equity
securities
|
58 | % | 64 | % | 72 | % | 74 | % | ||||||||
|
Debt
securities
|
37 | % | 31 | % | 25 | % | 26 | % | ||||||||
|
Real
estate and other
|
5 | % | 5 | % | 3 | % | - | |||||||||
|
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 2009, and for
postretirement plans of 75 percent equities and 25 percent debt for
2009. 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, 2008 and 2007
follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
|
Benefit
obligation, end of period
|
$ | 260.6 | $ | 249.6 | $ | 72.3 | $ | 70.2 | ||||||||
|
Fair
value of plan assets, end of period
|
(150.9 | ) | (211.8 | ) | (4.3 | ) | (6.8 | ) | ||||||||
|
Post
measurement date adjustments
|
- | (2.4 | ) | - | (1.1 | ) | ||||||||||
|
Funded
status, end of period:
|
$ | 109.7 | $ | 35.4 | $ | 68.0 | $ | 62.3 | ||||||||
|
Accrued
liabilities
|
$ | 0.7 | $ | 0.7 | $ | 4.3 | $ | 3.9 | ||||||||
|
Other
liabilities
|
$ | 109.0 | $ | 34.7 | $ | 63.7 | $ | 58.4 | ||||||||
As of
December 31, 2008 and 2007, the funded status of the SERP, which is included in
Pension Benefits in the chart above, was an unfunded amount of $14.6 million and
$13.1 million, respectively.
Prior Service Cost,
Actuarial Gains and Losses, and Transition Obligation
Effects
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 | |||||||||||||
|
Amounts
arising during the period
|
0.4 | 79.1 | - | 4.6 | - | |||||||||||||||
|
Reclassification
to benefit costs
|
(2.1 | ) | (0.1 | ) | 1.0 | - | (1.4 | ) | ||||||||||||
|
Balance
December 31, 2008
|
$ | 9.5 | $ | 90.9 | $ | (3.7 | ) | $ | 3.5 | $ | 6.2 | |||||||||
Due to
moving the measurement date from September 30 to December 31, in accordance with
SFAS 158, the 2008 roll forwards of prior service cost, actuarial gains and
losses, and transition obligations include 15 months of activity.
Following
is a reconciliation of the amounts in Accumulated other comprehensive
income (AOCI) and Regulatory assets related to
retirement plan obligations at December 31, 2008 and 2007:
|
(In
millions)
|
2008
|
2007
|
||||||||||||||
|
Pensions
|
Other
Benefits
|
Pensions
|
Other
Benefits
|
|||||||||||||
|
Prior
service cost
|
$ | 9.5 | $ | (3.7 | ) | $ | 11.2 | $ | (4.7 | ) | ||||||
|
Unamortized
actuarial gain/(loss)
|
90.9 | 3.5 | 11.9 | (1.1 | ) | |||||||||||
|
Transition
obligation
|
- | 6.2 | - | 7.6 | ||||||||||||
| 100.4 | 6.0 | 23.1 | 1.8 | |||||||||||||
|
Less:
Regulatory asset
deferral
|
(95.4 | ) | (5.7 | ) | (21.9 | ) | (1.7 | ) | ||||||||
|
AOCI before
taxes
|
$ | 5.0 | $ | 0.3 | $ | 1.2 | $ | 0.1 | ||||||||
Related
to pension plans, $1.7 million of prior service cost and $2.2 million of
actuarial gain/loss is expected to be amortized to periodic cost in
2009. Related to other benefits, $1.1 million of the transition
obligation and $0.4 million of actuarial gain/loss is expected to be amortized
to periodic cost in 2009, and $0.8 million of prior service cost is expected to
reduce periodic cost in 2009.
Expected Cash
Flows
In 2009,
the Company expects to make contributions of approximately $25 to 30 million to
its pension plan trusts. In addition, the Company expects to make
payments totaling approximately $0.7 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 2008 (in millions) are $14.5 in 2009, $14.8 in 2010
$16.0 in 2011, $16.5 in 2012, $17.3 in 2013 and $101.3 in years
2014-2018. Expected benefit payments projected to be required for
postretirement benefits during the years following 2008 (in millions) are $6.9
in 2009, $7.3 in 2010, $7.6 in 2011, $7.9 in 2012, and $8.2 in 2012 and $46.0 in
years 2014-2018.
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 and
include an option to invest in Vectren common stock, among other
alternatives. During 2008, 2007 and 2006, the Company made
contributions to these plans of $4.1 million, $4.0 million, and $3.9 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,
2008 and 2007, the liability associated with these plans totaled $21.1 million
and $29.0 million, respectively, and is included in Deferred credits and other
liabilities. The impact of these plans on Other operating expenses was
income of $2.6 million in 2008, expense of $2.2 million in 2007 and expense of
$0.7 million in 2006.
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 corporate and utility
investments on the Consolidated Balance Sheets were $19.8 million and
$18.2 million at December 31, 2008 and 2007, respectively. Earnings from
those investments, which are recorded in Other-net, totaled a loss of
$2.8 million in 2008, earnings of $0.6 million in 2007, and earnings of $0.8
million in 2006.
|
10.
|
Borrowing
Arrangements
|
Long-Term
Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
|||||
|
(In
millions)
|
2008
|
2007
|
|||
|
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
|
|||
|
2036,
5.95%
|
99.1
|
100.0
|
|||
|
2039,
6.25%
|
124.3
|
-
|
|||
|
Total
Utility Holdings
|
823.4
|
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 0.9%, tax
exempt,
|
|||||
|
2008 weighted average: 2.78%
|
9.8
|
9.8
|
|||
|
2023,
1993 Environmental Improvement Series B, 5.15%, tax
exempt
|
22.6
|
22.6
|
|||
|
2025,
1998 Pollution Control Series A, current adjustable rate 1.2%, tax
exempt,
|
|||||
|
2008 weighted average: 2.94%
|
31.5
|
31.5
|
|||
|
2030,
1998 Pollution Control Series C, 5.35%, tax exempt
|
22.2 | 22.2 | |||
|
2041,
2007 Pollution Control Series, 5.45%, tax exempt
|
17.0
|
17.0 | |||
|
Total
SIGECO
|
245.2
|
245.2
|
|||
|
Indiana
Gas
|
|||||
|
Senior
Unsecured Notes
|
|||||
|
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
|
121.0
|
|||
|
At
December 31,
|
|||||
|
(In
millions)
|
2008
|
2007
|
|||
|
Vectren
Capital Corp.
|
|||||
|
Fixed
Rate Senior Unsecured Notes
|
|||||
|
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
|
182.5
|
|||
|
Other
Long-Term Notes Payable
|
0.7
|
0.3
|
|||
|
Total
long-term debt outstanding
|
1,372.8
|
1,249.0
|
|||
|
Current
maturities of long-term debt
|
(0.4)
|
(0.3)
|
|||
|
Debt
subject to tender
|
(80.0)
|
-
|
|||
|
Unamortized
debt premium & discount - net
|
(3.2)
|
(3.3)
|
|||
|
Treasury
debt
|
(41.3)
|
-
|
|||
|
Total
long-term debt-net
|
$ 1,247.9
|
$
1,245.4
|
|||
Utility
Holdings 2008 Debt Issuance
In March
2008, Utility Holdings issued at par $125 million in 6.25 percent senior
unsecured notes due April 1, 2039 (2039 Notes). The 2039 Notes are
guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas,
and VEDO. These guarantees are full and unconditional and joint and
several.
The 2039
Notes have no sinking fund requirements, and interest payments are due
monthly. The notes may be called by Utility Holdings, in whole or in
part, at any time on or after April 1, 2013, at 100 percent of principal amount
plus accrued interest. During 2007, Utility Holdings entered into
several interest rate hedges with an $80 million notional
amount. Upon issuance of the notes, these instruments were settled
resulting in the payment of approximately $9.6 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 2039 Notes less settlement
of the hedging arrangements and payments of issuance costs amounted to
approximately $111.1 million.
Utility
Holdings 2006 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. The proceeds
from the sale of the 2036 Notes, settlement of the hedging arrangements, and
payments of issuance costs totaled approximately $92.8 million.
Long-Term
Debt Put and Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. Other than certain instruments that
can be put to the Company upon the death of the holder (death puts), these put
or call provisions are not triggered by specific events, but are based upon
dates stated in the note agreements. During 2008 the Company repaid
approximately $1.6 million related to death puts. In 2007 and 2006,
no debt was put to the Company. Debt which may be put to the Company
for reasons other than a death during the years following 2008 (in millions) is
$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.
Auction
Rate Securities
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt had a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate was to 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 (Ambac).
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax-exempt auction rate mode long-term debt, including the $17
million issued in December 2007, of its plans to convert that debt from its
current auction rate mode into a daily interest rate mode. In March
2008, the debt was tendered at 100 percent of the principal amount plus accrued
interest. During March 2008, SIGECO remarketed approximately $61.8
million of these instruments at interest rates that are fixed to maturity,
receiving proceeds, net of issuance costs, of approximately $60.0
million. The terms are $22.6 million at 5.15 percent due in 2023,
$22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due
in 2041. The remaining $41.3 million continues to be held in treasury
and is expected to be remarketed in 2009.
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. The note had a stated interest rate of
7.25 percent.
Other
Financing Transactions
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 was retired as
scheduled.
Future
Long-Term Debt Sinking Fund Requirements and 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 2009 sinking fund
requirement by this means and, accordingly, the sinking fund requirement for
2009 is excluded from Current
liabilities in the Consolidated Balance Sheets. At December
31, 2008, $1.0 billion of SIGECO's utility plant remained unfunded under
SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance
subject to the Mortgage Indenture approximated $2.3 billion at December 31,
2008.
Consolidated
maturities of long-term debt during the five years following 2008 (in millions)
are zero in 2009, $47.5 in 2010, $250.0 in 2011, $60.0 in 2012, and 105.0 in
2013.
Debt
Guarantees
Vectren
Corporation guarantees Vectren Capital’s long-term and short-term debt, which
totaled $183 million and $327 million, respectively, at December 31,
2008. 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, 2008, totaled $823 million and $192 million,
respectively.
Short-Term
Borrowings
At
December 31, 2008, the Company had $905 million of short-term borrowing
capacity, including $520 million for the Utility Group operations and $385
million for the wholly owned Nonutility Group and corporate operations, of which
approximately $328 million was available for the Utility Group operations and
approximately $55 million was available for wholly owned Nonutility Group and
corporate operations, as reduced for approximately $3 million in outstanding
letters of credit.
Interest
rates and outstanding balances associated with short-term borrowing arrangements
follows.
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Weighted
average commercial paper and bank loans
|
||||||||||||
|
outstanding
during the year
|
$ | 388.0 | $ | 391.3 | $ | 256.1 | ||||||
|
Weighted
average interest rates during the year
|
||||||||||||
|
Commercial
paper
|
3.76 | % | 5.54 | % | 5.16 | % | ||||||
|
Bank
loans
|
3.22 | % | 5.61 | % | 5.51 | % | ||||||
|
At
December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
||||||||||
|
Commercial
paper
|
$ | 91.5 | $ | 385.9 | ||||||||
|
Bank
loans
|
428.0 | 171.1 | ||||||||||
|
Total
short-term borrowings
|
$ | 519.5 | $ | 557.0 | ||||||||
Vectren
Capital Short Term Debt Issuance
On
September 11, 2008, Vectren Capital entered into a 364-day $120 million
credit agreement that was syndicated with 7 banks. The agreement
provides for revolving loans and letters of credit up to $120 million and is in
addition to Vectren Capital’s $255 million which expires in November
2010. Borrowings under the supplemental one year agreement may be at
a floating rate or a Eurodollar rate. Current floating rate
advances would be priced at the greater of the Federal Funds Rate plus
0.5 percent or the Prime Rate. Current Eurodollar advances, based on
Vectren's current credit rating, would expect to be priced at the appropriate
Libor rate plus 0.65 percent.
Impacts
on Short-Term Borrowings from Recent Events in Credit Markets
Historically,
the Company has funded the short-term borrowing needs of Utility Holdings’
operations through the commercial paper market. In 2008, the
Company’s access to longer term commercial paper was significantly reduced as a
result of the continued turmoil and volatility in the financial markets.
As a result, the Company has met working capital requirements through a
combination of A2/P2 commercial paper issuances and draws on Utility
Holdings’ $515 million commercial paper back-up credit facilities, which expires
in November of 2010. In addition, the Company increased its cash
investments by approximately $75 million during the fourth quarter of
2008. These cash positions were liquidated in January 2009 based upon
improvements in the short-term debt and commercial paper
markets. Their liquidation resulted in an increase to the available
short-term debt capacity for Utility Holdings by $40 million and for the Vectren
Capital by $35 million.
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 an example, the Vectren
Capital’s short-term debt agreement expiring in 2010 contains a covenant that
the ratio of consolidated total debt to consolidated total capitalization will
not exceed 65 percent. As of December 31, 2008, the Company was in
compliance with all financial covenants.
|
11.
|
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 allowed
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.
On June
27, 2008, the Company physically settled the equity forward by delivering the
4.6 million shares, receiving proceeds of approximately $124.9 million.
The slight difference between the proceeds generated by the public offering and
those received by the Company were due to adjustments defined in the equity
forward agreement including: 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.
Vectren
transferred the proceeds to Utility Holdings, and Utility Holdings used the
proceeds to repay short-term debt obligations incurred primarily to fund its
capital expenditure program. The proceeds received were recorded as an
increase to Common
Stock in Common Shareholders’ Equity and are presented in the Statement
of Cash Flows as a financing activity.
Authorized, Reserved Common
and Preferred Shares
At
December 31, 2008 and 2007, 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 5.6 million shares at December 31,
2008 and 6.3 million shares at December 31, 2007, 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, 2008,
and 2007, there were 393.4 million and 396.4 million, respectively, of
authorized shares of common stock and all authorized shares of preferred stock,
available for a variety of general corporate purposes, including future public
offerings to raise additional capital and for facilitating
acquisitions.
Shareholder Rights
Agreement
The
Company’s board of directors previously adopted a Shareholder Rights Agreement
(Rights Agreement). As part of the Rights Agreement, the board of
directors declared a dividend distribution of one right for each outstanding
Vectren common share. Each right entitles the holder to purchase from
Vectren one share of common stock at a price of $65.00 per share (subject to
adjustment to prevent dilution). The rights become exercisable 10
days following a public announcement that a person or group of affiliated or
associated persons (Vectren Acquiring Person) has acquired beneficial ownership
of 15 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 and is not expected to be
renewed.
|
12.
|
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 that stock options and an
equity forward contract are converted into common shares using the treasury
stock method and restricted shares are converted into common shares using the
contingently issuable shares method, to the extent the effect would be
dilutive. See Note 10 regarding the settlement of the equity forward
contract.
The
following table illustrates the basic and dilutive earnings per share
calculations for the three years ended December 31, 2008:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share data)
|
2008
|
2007
|
2006
|
|||||||||
|
Numerator:
|
||||||||||||
|
Numerator
for basic and diluted EPS - Net income
|
$ | 129.0 | $ | 143.1 | $ | 108.8 | ||||||
|
Denominator:
|
||||||||||||
|
Denominator
for basic EPS - Weighted average
|
||||||||||||
|
common
shares outstanding
|
78.3 | 75.9 | 75.7 | |||||||||
|
Equity
forward dilution effect
|
0.1 | 0.1 | - | |||||||||
|
Conversion
of stock options and lifting of
|
||||||||||||
|
restrictions
on issued restricted stock
|
0.5 | 0.6 | 0.5 | |||||||||
|
Denominator
for diluted EPS - Adjusted weighted
|
||||||||||||
|
average
shares outstanding and assumed
|
||||||||||||
|
conversions
outstanding
|
78.9 | 76.6 | 76.2 | |||||||||
|
Basic
earnings per share
|
$ | 1.65 | $ | 1.89 | $ | 1.44 | ||||||
|
Diluted
earnings per share
|
$ | 1.63 | $ | 1.87 | $ | 1.43 | ||||||
For the
years ended December 31, 2008, 2007, and 2006, all options were
dilutive.
|
13.
|
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,
non-vested shares (herein referred to as restricted stock), and restricted stock
units. 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 and restricted
units 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.
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)
|
2008
|
2007
|
2006
|
|||||||||
|
Total
cost of share-based compensation
|
$ | 3.7 | $ | 2.5 | $ | 3.2 | ||||||
|
Less
capitalized cost
|
0.9 | 0.5 | 0.9 | |||||||||
|
Total
in other operating expense
|
2.8 | 2.0 | 2.3 | |||||||||
|
Less
income tax benefit in earnings
|
1.1 | 0.8 | 0.6 | |||||||||
|
After
tax effect of share-based compensation
|
$ | 1.7 | $ | 1.2 | $ | 1.7 | ||||||
Restricted Stock and
Restricted Stock Unit Related Matters
The
Company periodically grants restricted stock and/or restricted stock units to
executives and other key non-officer employees. The vesting of those
grants 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.
A summary
of the status of the Company’s restricted stock and restricted unit awards
separated between those accounted for as liabilities and equity as of December
31, 2008, and changes during the year ended December 31, 2008,
follows:
|
Equity
Awards
|
||||||||||||||||
|
Wtd.
Avg.
|
||||||||||||||||
|
Grant
Date
|
Liability
Awards
|
|||||||||||||||
|
Shares
|
Fair
value
|
Shares/Units
|
Fair
value
|
|||||||||||||
|
Restricted
at January 1, 2008
|
21,870 | $ | 28.11 | 351,888 | ||||||||||||
|
Granted
|
16,695 | $ | 28.66 | 190,832 | ||||||||||||
|
Vested
|
- | $ | - | (14,688 | ) | |||||||||||
|
Forfeited
|
(2,330 | ) | $ | 28.52 | (3,639 | ) | ||||||||||
|
Restricted
at December 31, 2008
|
36,235 | $ | 28.24 | 524,393 | $ | 25.01 | ||||||||||
As of
December 31, 2008, there was $5.8 million of total unrecognized compensation
cost related to restricted stock awards. That cost is expected to be
recognized over a weighted-average period of 1.7 years. The total fair
value of shares vested for awards to executives and non-employee directors
(Liability Awards) during the years ended December 31, 2008, 2007, and 2006, was
$0.4 million, $1.9 million, and $1.8 million, respectively. No awards
to key non-officer employees (Equity Awards) vested in 2008 or
2006. The total fair value of shares vested for awards to key
non-officer employees during the year ended December 31, 2007, was $0.1
million.
On
February 11, 2009, the Company issued 234,450 restricted units to executives and
other key non-officer employees. These agreements have different
terms compared previous awards. Awards to executives were only in the
form of restricted units and can only be settled in cash. Further,
dividends on those awards are performance based and are converted into
equivalent restricted units based on the closing price of Vectren’s stock on the
payment date, and therefore are subject to forfeiture. Non-officer
awards were time based, not performance based, and can only be settled in
cash. In addition, on February 11, 2009, participants forfeited
56,905 shares related to awards measured during the three year performance
period ending December 31, 2008.
Stock Option Related
Matters
In the
past, option awards were granted to executives and other key employees with an
exercise price equal to the market price of the Company’s stock at the date of
grant; those option awards generally required 3 years of continuous service and
have 10-year contractual terms. These awards generally vested on a
pro-rata basis over 3 years. The last option grant occurred in 2005,
and the Company does not intend to issue options in the future.
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.
A summary
of the status of the Company’s stock option awards as of December 31, 2008, and
changes during the year ended December 31, 2008, follows:
|
Weighted
average
|
Aggregate
|
|||||||||||||||
|
Remaining
|
Intrinsic
|
|||||||||||||||
|
Shares
|
Exercise
|
Contractual
|
Value
|
|||||||||||||
|
Price
|
Term
(years)
|
(In
millions)
|
||||||||||||||
|
Outstanding
at January 1, 2008
|
1,432,774 | $ | 23.86 | |||||||||||||
|
Granted
|
- | $ | - | |||||||||||||
|
Exercised
|
(97,560 | ) | $ | 22.52 | ||||||||||||
|
Forfeited
or expired
|
- | $ | - | |||||||||||||
|
Outstanding
at December 31, 2008
|
1,335,214 | $ | 23.95 | 4.1 | $ | 1.9 | ||||||||||
|
Exercisable
at December 31, 2008
|
1,335,214 | $ | 23.95 | 4.1 | $ | 1.9 | ||||||||||
The total
intrinsic value of options exercised during the twelve months ended December 31,
2008, 2007, and 2006 was $0.5 million, $3.6 million, and $0.8 million,
respectively. As of December 31, 2008, all compensation cost has been
recognized. The actual tax benefit realized for tax deductions from
option exercises was approximately $0.1 million in 2008, $1.2 million in 2007,
and $0.2 million in 2006.
The
Company periodically issues new shares and also from time to time repurchases
shares to satisfy share option exercises. During the year ended
December 31, 2008, 2007, and 2006, the Company received cash upon exercise of
stock options totaling approximately $1.9 million, $11.4 million, and $3.2
million, respectively. During those periods, the Company repurchased
shares totaling $2.2 million in 2008, $6.9 million in 2007, and $3.8 million in
2006. The Company does not expect future period repurchase activity
to be materially different.
Deferred Compensation Plan
Matters
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, 2008, 2007, and 2006, was a cost
of $0.6 million, a cost of $0.4 million and a benefit of $0.3 million,
respectively.
|
14.
|
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 2008 and thereafter (in millions) are $6.6 in 2009, $4.5 in 2010, $2.3
in 2011, $1.5 in 2012, $1.2 in 2013, and $0.5 thereafter. Total lease
expense (in millions) was $8.8 in 2008, $8.7 in 2007, and $8.5 in
2006.
Firm
nonutility purchase commitments for commodities by consolidated companies total
(in millions) $55.3 in 2009, $5.2 in 2010-2013. Firm purchase
commitments for utility and nonutility plant total (in millions) $45.1 in 2009,
and zero in 2010-2013.
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.
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,
2008, 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 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.”
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.
|
15.
|
Environmental
Matters
|
Clean Air
Act
In March
of 2005, the USEPA finalized the Clean Air Interstate Rule (CAIR). CAIR is an
allowance cap and trade program requiring further reductions from coal-burning
power plants in NOx emissions beginning January 1, 2009 and SO2 emissions
beginning January 1, 2010, with a second phase of reductions in 2015. On
July 11, 2008, the US Court of Appeals for the District of Columbia vacated the
federal CAIR regulations. Various parties filed motions for
reconsideration, and on December 23, 2008, the Court reinstated the CAIR
regulations and remanded the regulations back to the USEPA for promulgation of
revisions in accordance with the Court’s July 11, 2008 Order. Thus,
the original version of CAIR promulgated in March of 2005 remains effective
while USEPA revises it per the Court’s guidance. It is possible that
a revised CAIR will require further reductions in NOx and SO2 from
SIGECO’s generating units. SIGECO is in compliance with the current
CAIR Phase I annual NOx reduction requirements in effect on January 1,
2009. Utilization of the Company’s inventory of NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of the these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. It is quite possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress. It is also possible that the USEPA will promulgate
a revised mercury regulation in 2009.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. 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 allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. Through
December 31, 2008, the Company has invested approximately $97.6 million in this
project. The scrubber was placed into service on January 1, 2009, and
the Company expects the total project investment to approximate $100 million
once all post in-service investments are completed. Recovery through
a rider mechanism of associated operating expenses including depreciation
expense associated with the scrubber also began on January 1,
2009. With the SO2 scrubber
fully operational, SIGECO is positioned for compliance with the additional
SO2
reductions required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s
coal fired generating fleet is 100 percent scrubbed for SO2 and 90
percent controlled for NOx. SIGECO's investments in scrubber, SCR and
fabric filter technology allows for compliance with existing regulations and
should position it to comply with future reasonable pollution control
legislation, if and when, reductions in mercury and further reductions in NOx
and SO2 are
promulgated by USEPA.
Climate
Change
There are
currently several forms of legislation being circulated at the federal level
addressing the climate change issue. These proposals generally
involve either: 1) a “cap and trade” approach where there is a progressive cap
on greenhouse gas emissions and an auctioning and subsequent trading of
allowances among those that emit greenhouse gases or 2) a carbon
tax. Currently no legislation has passed either house of
Congress.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in the State
of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas
Reduction Accord, and its legislature has in the recent past debated, but did
not pass, renewable energy portfolio standards. It is expected that
the Indiana State legislature will address a renewable energy portfolio standard
again in 2009.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from new motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. Should the USEPA find such endangerment, it is likely
that major stationary sources will be subject to regulation under the
Act. In 2008, the USEPA published its Advanced Notice of Proposed
Rulemaking in which the agency solicited comment as to whether it is appropriate
or effective to regulate greenhouse gas emissions under the Act. The
Obama administration has asserted that it will act on the endangerment finding
in the absence of comprehensive federal legislation within the next 18
months.
Impact
of Legislative Actions and Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants,
nonutility coal mining operations, and possibly natural gas distribution
businesses. Further, any legislation would likely impact the Company’s
generation resource planning decisions. 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. The Company has gathered preliminary estimates of the costs to
comply with a cap and trade approach to controlling greenhouse gas
emissions. A preliminary investigation demonstrated costs to comply
would be significant, first to operating expenses for the purchase of
allowances, and later to capital expenditures as technology becomes available to
control greenhouse gas emissions. However, these compliance cost
estimates are very sensitive to highly uncertain assumptions, including
allowance prices. Costs to purchase allowances that cap greenhouse
gas emissions should be considered a cost of providing electricity, and as such,
the Company believes recovery should be timely reflected in rates charged to
customers. Approximately 22 percent of electric volumes sold in 2008
were delivered to municipal and other wholesale customers. As such,
the Company has some flexibility to modify the level of these transactions to
reduce overall emissions and reduce costs associated with complying with new
environmental regulations.
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 owned or
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 cumulative costs
that it reasonably expects to incur totaling approximately $21.6
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 $20.5
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 cumulative costs that it reasonably expects to incur totaling
approximately $8.7 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 of $8.0 million.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. 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. As of December 31, 2008, approximately $6.5 million is
included in Other
Liabilities related to the remediation of these sites.
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.
|
16.
|
Rate
& Regulatory Matters
|
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Order Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also adjusts the rate design that will be used to collect the agreed-upon
revenue from VEDO's residential customers. The order authorizes the
use of a straight fixed variable rate design which places all, or most, of the
fixed cost recovery in the customer service charge. Using a phased in
approach, revenues based on volumes sold will be entirely replaced with a fixed
charge after one year. A straight fixed variable design
mitigates some weather risk as well as the effects of declining usage, similar
to the Company’s lost margin recovery mechanism, which expired when this new
rate design went into effect in February 2009. In 2008, results include
approximately $4.3 million of revenue from the existing lost margin recovery
mechanism that will not continue once this base rate increase is in
effect. The OCC has filed a request for rehearing on the rate design
finding by the PUCO. The rehearing request mirrors similar requests filed
by the OCC in each case where the PUCO has approved similar rate designs, and
all such requests have been denied.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of bad debt and percent of
income payment plan (PIPP) expenses; base rate recovery of pipeline integrity
management expense; timely recovery of costs associated with the accelerated
replacement of bare steel and cast iron pipes, as well as certain service
risers; and expanded conservation programs now totaling up to $5 million in
annual expenditures.
Vectren Energy Delivery of
Ohio, Inc. Begins Process to Exit the Merchant Function
On August
20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers
to provide the gas commodity to the Company for resale to its customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. This auction, which is effective from October 1, 2008 through
March 31, 2010, is the initial step in exiting the merchant function in the
Company’s Ohio service territory. The approach eliminates the
need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits. On October 1st, VEDO’s
entire natural gas inventory was transferred, receiving proceeds of
approximately $107 million. The PUCO has also provided for an Exit
Transition Cost rider, which allows the Company to recover costs associated with
the transition. As the cost of gas is currently passed through to
customers through a PUCO approved recovery mechanism, the impact of exiting the
merchant function should not have a material impact on Company earnings or
financial condition.
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
the settlement agreement reached in its Vectren North gas rate case. The
order provided for a base rate increase of $16.3 million and a return on equity
(ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate
base of approximately $793 million. The order 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 a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s electric rate case. The order
provided for an approximate $60.8 million electric rate increase to cover the
Company’s cost of system growth, maintenance, safety and reliability. The
order provided 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 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 ROE of 10.4
percent.
Vectren South Gas Base Rate
Order Received
On August
1, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s gas rate case. The order provided
for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an
overall rate of return of 7.2 percent on rate base of approximately $122
million. The order also provided 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 a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
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. Since April 1, 2005, the Company has been an active participant
in the MISO energy markets, bidding its owned generation into the Day Ahead and
Real Time markets and procuring 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 as generation capacity is
in excess of that needed to serve native load and is only occasionally in a net
purchase position. 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. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO day ahead and real-time markets. Net revenues from wholesale
activities included in Electric Utility revenues
totaled $57.6 million in 2008, $39.8 million in 2007 and $29.8 million in
2006.
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. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered/refunded through tracking
mechanisms.
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 Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM
The need
to expend capital for improvements to the regional 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
timely recovers its investment in certain new electric transmission projects
that benefit the MISO infrastructure at a FERC approved rate of
return.
|
17.
|
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 and any associated collateral 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 hedged item 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 four primary areas: synfuels risk
management, SO2 emission
allowance risk management, natural gas procurement, and interest rate risk
management.
Synfuel Risk
Management
As
discussed in Note 5, 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 as
of December 31, 2007 and was received in 2008. The pretax impact of
an insurance contract related to synfuels was a loss of $0.3 million in 2007 and
earnings of $3.1 million in 2006. These results are also recorded in
Other-
net.
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, 2008, a deferred gain of
approximately $0.2 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. No SO2 emission
allowance hedges are outstanding as of December 31, 2008.
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
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, 2008 and 2007, 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.
As of
December 31, 2008, no interest rate swaps were outstanding. At
December 31, 2007, the fair value liability associated with interest rate swaps
was $8.9 million. Related to derivative instruments associated with
completed debts issuances, an approximate $7.7 million net regulatory asset
remains at December 31, 2008. In 2008, $0.3 million was reclassified as a
decrease to interest expense, $0.6 million reduced interest expense in 2007, and
$0.7 million reduced interest expense in 2006. The Company estimates
a $0.3 million reduction to interest expense will occur in 2009 related to the
amortization of this net position.
Fair Value
Measurements
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. SFAS 157 does not
require any new fair value measurements; however, the standard will impact how
other fair value based GAAP is applied. Subsequently, the FASB issued
FSP FAS 157-2 which delayed 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) to fiscal years beginning after November 15,
2008. The Company adopted SFAS 157 on January 1, 2008, except as it
applies to those nonfinancial assets and nonfinancial liabilities as described
in FSP FAS 157-2. The partial adoption of SFAS 157 did not materially
impact Vectren’s financial position, results of operations or cash
flows. The potential impact of applying SFAS 157 to its nonfinancial
assets and liabilities is not expected to have a material impact on the
Company’s consolidated financial statements.
Vectren
measures certain financial instruments, primarily derivatives, at fair value on
a recurring basis. SFAS 157 defines a hierarchy for disclosing fair value
measurements based primarily on the level of public data used in determining
fair value. Level 1 inputs include quoted market prices in active markets
for identical assets or liabilities; Level 2 inputs include inputs other than
Level 1 inputs that are directly or indirectly observable; and Level 3 inputs
include unobservable inputs using estimates and assumptions developed in-house,
which reflect what a market participant would use to determine fair value.
At December 31, 2008, other than $75 million invested in money market funds and
included in Cash and cash
equivalents, the Company had no material assets or liabilities recorded
at fair value outstanding and none outstanding valued using Level 3
inputs. The money market investments are valued using Level 1
inputs. As of December 31, 2007, the Company had derivatives in Prepayments and other current
assets managing synfuel risk totaling $22.8 million and totaling $2.6
million in other derivative instruments. In addition, there was $8.9
million in Accrued liabilities
related to derivatives managing interest rate
risk.
SFAS 159
Also on
January 1, 2008, the Company adopted 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 permitted entities to choose
to measure many financial instruments and certain other items at fair
value. The Company did not choose to apply the option provided in
SFAS 159 to any of its eligible items; therefore, its adoption did not have any
impact on the Company’s financial statements or results of
operations.
Fair Value of Other
Financial Instruments
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
||||||||||||||||
|
2008
|
2007
|
|||||||||||||||
|
(In
millions)
|
Carrying
Amount
|
Est.
Fair Value
|
Carrying
Amount
|
Est.
Fair Value
|
||||||||||||
|
Long-term
debt
|
$ | 1,372.8 | $ | 1,251.0 | $ | 1,249.0 | $ | 1,236.6 | ||||||||
|
Short-term
borrowings & notes payable
|
519.5 | 519.5 | 557.0 | 557.0 | ||||||||||||
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.
Because
of the customized nature of notes receivable 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, 2008 and 2007, the fair value for these
financial instruments was not estimated.
|
18.
|
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 power 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 wholesale power
operations. In total, regulated operations supply natural gas and /or
electricity to over one million customers.
The
Nonutility Group is comprised of one operating segment that includes various
subsidiaries and affiliates investing in energy marketing and services, coal
mining, and energy infrastructure services, among other energy-related
opportunities.
Corporate
and Other includes unallocated corporate expenses such as 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)
|
2008
|
2007
|
2006
|
|||||||||
|
Revenues
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Electric
Utility Services
|
524.2 | 487.9 | 422.2 | |||||||||
|
Other
Operations
|
36.8 | 40.4 | 36.6 | |||||||||
|
Eliminations
|
(35.0 | ) | (38.7 | ) | (34.8 | ) | ||||||
|
Total
Utility Group
|
1,958.7 | 1,759.0 | 1,656.5 | |||||||||
|
Nonutility
Group
|
664.7 | 643.4 | 503.2 | |||||||||
|
Eliminations
|
(138.7 | ) | (120.5 | ) | (118.1 | ) | ||||||
|
Consolidated
Revenues
|
$ | 2,484.7 | $ | 2,281.9 | $ | 2,041.6 | ||||||
|
Profitability
Measures - Net Income
|
||||||||||||
|
Gas
Utility Services
|
$ | 53.3 | $ | 41.7 | $ | 41.5 | ||||||
|
Electric
Utility Services
|
50.7 | 52.6 | 41.6 | |||||||||
|
Other
Operations
|
7.1 | 12.2 | 8.3 | |||||||||
|
Utility
Group Net Income
|
111.1 | 106.5 | 91.4 | |||||||||
|
Nonutility
Group Net Income
|
18.9 | 37.0 | 18.1 | |||||||||
|
Corporate
& Other Net Loss
|
(1.0 | ) | (0.4 | ) | (0.7 | ) | ||||||
|
Consolidated
Net Income
|
$ | 129.0 | $ | 143.1 | $ | 108.8 | ||||||
|
Amounts
Included in Profitability Measures
|
||||||||||||
|
Depreciation
& Amortization
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 74.1 | $ | 70.6 | $ | 67.6 | ||||||
|
Electric
Utility Services
|
68.5 | 66.0 | 61.8 | |||||||||
|
Other
Operations
|
22.9 | 21.8 | 21.9 | |||||||||
|
Total
Utility Group
|
165.5 | 158.4 | 151.3 | |||||||||
|
Nonutility
Group
|
26.8 | 26.4 | 21.0 | |||||||||
|
Consolidated
Depreciation & Amortization
|
$ | 192.3 | $ | 184.8 | $ | 172.3 | ||||||
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Interest
Expense
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 42.0 | $ | 39.8 | $ | 40.7 | ||||||
|
Electric
Utility Services
|
32.0 | 29.6 | 28.6 | |||||||||
|
Other
Operations
|
5.9 | 11.2 | 8.2 | |||||||||
|
Total
Utility Group
|
79.9 | 80.6 | 77.5 | |||||||||
|
Nonutility
Group
|
17.3 | 21.9 | 20.0 | |||||||||
|
Corporate
& Other
|
0.6 | (1.5 | ) | (1.9 | ) | |||||||
|
Consolidated
Interest Expense
|
$ | 97.8 | $ | 101.0 | $ | 95.6 | ||||||
|
Income
Taxes
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 35.5 | $ | 33.2 | $ | 22.6 | ||||||
|
Electric
Utility Services
|
32.0 | 38.0 | 25.3 | |||||||||
|
Other
Operations
|
0.1 | (4.5 | ) | (0.2 | ) | |||||||
|
Total
Utility Group
|
67.6 | 66.7 | 47.7 | |||||||||
|
Nonutility
Group
|
9.5 | 10.5 | (17.6 | ) | ||||||||
|
Corporate
& Other
|
(1.0 | ) | (1.2 | ) | 0.2 | |||||||
|
Consolidated
Income Taxes
|
$ | 76.1 | $ | 76.0 | $ | 30.3 | ||||||
|
Capital
Expenditures
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 110.4 | $ | 128.9 | $ | 76.8 | ||||||
|
Electric
Utility Services
|
172.0 | 134.7 | 156.8 | |||||||||
|
Other
Operations
|
29.6 | 36.4 | 24.8 | |||||||||
|
Non-cash
costs & changes in accruals
|
(8.3 | ) | (0.2 | ) | (11.8 | ) | ||||||
|
Total
Utility Group
|
303.7 | 299.8 | 246.6 | |||||||||
|
Nonutility
Group
|
87.3 | 34.7 | 34.8 | |||||||||
|
Consolidated
Capital Expenditures
|
$ | 391.0 | $ | 334.5 | $ | 281.4 | ||||||
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Assets
|
||||||||
|
Utility
Group
|
||||||||
|
Gas
Utility Services
|
$ | 2,204.7 | $ | 2,287.4 | ||||
|
Electric
Utility Services
|
1,462.1 | 1,369.2 | ||||||
|
Other
Operations, net of eliminations
|
171.3 | (12.9 | ) | |||||
|
Total
Utility Group
|
3,838.1 | 3,643.7 | ||||||
|
Nonutility
Group
|
780.1 | 704.1 | ||||||
|
Corporate
& Other
|
737.5 | 450.3 | ||||||
|
Eliminations
|
(722.8 | ) | (501.7 | ) | ||||
|
Consolidated
Assets
|
$ | 4,632.9 | $ | 4,296.4 | ||||
|
19.
|
Additional
Balance Sheet & Statement of Income
Information
|
Prepayments and other current
assets in the Consolidated Balance Sheets consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Prepaid
gas delivery service
|
$ | 75.0 | $ | 65.2 | ||||
|
Deferred
income taxes
|
8.2 | 29.9 | ||||||
|
Synfuels
related derivatives
|
- | 22.8 | ||||||
|
Prepaid
taxes
|
14.1 | 9.8 | ||||||
|
Other
prepayments & current assets
|
27.3 | 32.8 | ||||||
|
Total
prepayments & other current assets
|
$ | 124.6 | $ | 160.5 | ||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Refunds
to customers & customer deposits
|
$ | 45.5 | $ | 43.7 | ||||
|
Accrued
taxes
|
46.3 | 34.2 | ||||||
|
Accrued
interest
|
19.2 | 17.4 | ||||||
|
Asset
retirement obligation
|
7.2 | 9.5 | ||||||
|
Accrued
salaries & other
|
56.8 | 67.0 | ||||||
|
Total
accrued liabilities
|
$ | 175.0 | $ | 171.8 | ||||
Other Utility and Corporate Investments in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Cash
surrender value of life insurance policies
|
$ | 19.8 | $ | 18.2 | ||||
|
Municipal
bond
|
4.5 | 4.7 | ||||||
|
Restricted
cash
|
- | 2.2 | ||||||
|
Other
investments
|
1.4 | 1.2 | ||||||
|
Total
other investments
|
$ | 25.7 | $ | 26.3 | ||||
Equity in earnings of unconsolidated
affiliates in the Consolidated Statements of Income consists of the
following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
ProLiance
Holdings , LLC
|
$ | 39.5 | $ | 41.0 | $ | 35.3 | ||||||
|
Haddinton
Energy Partners, LP
|
(0.2 | ) | (0.2 | ) | 0.3 | |||||||
|
Pace
Carbon Synfuels, LP
|
- | (20.0 | ) | (17.8 | ) | |||||||
|
Other
|
(1.9 | ) | 2.1 | (0.8 | ) | |||||||
|
Total
equity in earnings of unconsolidated affiliates
|
$ | 37.4 | $ | 22.9 | $ | 17.0 | ||||||
Other – net in the
Consolidated Statements of Income consists of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
AFUDC
& capitalized interest
|
$ | 6.2 | $ | 6.3 | $ | 5.3 | ||||||
|
Interest
income
|
2.3 | 2.9 | 4.0 | |||||||||
|
Synfuel-related
activity
|
- | 23.4 | (11.4 | ) | ||||||||
|
Commerical
real estate impairment charge
|
(5.2 | ) | - | - | ||||||||
|
Broadband
charges
|
- | 0.1 | (1.9 | ) | ||||||||
|
Cash
surrender value of life insurance policies
|
(2.8 | ) | 0.6 | 0.8 | ||||||||
|
All
other income
|
1.6 | 3.5 | 0.5 | |||||||||
|
Total
other – net
|
$ | 2.1 | $ | 36.8 | $ | (2.7 | ) | |||||
|
20.
|
Impact
of Recently Issued Accounting
Guidance
|
SFAS 141 (Revised
2007)
In
December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS
141R). SFAS 141R 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 141R 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 141R 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 141R 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 No. 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
the impact is not expected to be material to the Company’s financial position or
results of operations.
SFAS 161
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS
161). SFAS 161 enhances the current disclosures under SFAS 133 and
requires that objectives for using derivative instruments be disclosed in terms
of underlying risk and accounting designation in order to better convey the
purpose of derivative use in terms of the risks that the entity is intending to
manage. Entities are required to provide enhanced disclosures about
(a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. Tabular disclosure of fair value amounts and gains and
losses on derivative instruments and related hedged items is
required. SFAS 161 is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
adoption encouraged. The Company will adopt SFAS 161 on January 1,
2009, and the impact is not expected to be material to the Company’s financial
position or results of operations.
SFAS 162
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of
accounting principles and the framework for selecting principles used in the
preparation of financial statements. SFAS No. 162 is effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity
with Generally Accepted Accounting Principles”. The implementation of this
standard will not have a material impact on its financial position and results
of operations.
FSP EITF
03-6-1
In June
2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted
in Share-Based Payment Transactions Are Participating Securities” (FSP EITF
03-6-1). FSP EITF 03-6-1 clarified that all outstanding unvested share-based
payment awards that contain rights to nonforfeitable dividends participate in
undistributed earnings with common shareholders. Awards of this nature are
considered participating securities and the two-class method of computing basic
and diluted earnings per share must be applied. FSP EITF 03-6-1 is effective for
fiscal years beginning after December 15, 2008. The Company will
adopt FSP EITF 03-6-1on January 1, 2009, and the impact is not expected to be
material to the Company’s financial position or results of
operations.
|
21.
|
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 2008 and 2007
follows:
|
(In
millions, except per share amounts)
|
Q1
|
Q2
|
Q3
|
Q4
|
||||||||||||
|
2008
|
||||||||||||||||
|
Operating
revenues
|
$ | 902.1 | $ | 463.9 | $ | 411.4 | $ | 707.3 | ||||||||
|
Operating
income
|
108.8 | 33.0 | 43.2 | 78.4 | ||||||||||||
|
Net
income
|
64.0 | 4.7 | 23.2 | 37.1 | ||||||||||||
|
Earnings
per share:
|
||||||||||||||||
|
Basic
|
$ | 0.84 | $ | 0.06 | $ | 0.29 | $ | 0.46 | ||||||||
|
Diluted
|
0.84 | 0.06 | 0.29 | 0.46 | ||||||||||||
|
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 | ||||||||||||
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, 2008, 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, 2008, 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,
2008, 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, 2008.
The
effectiveness of internal control over financial reporting as of December 31,
2008, 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 2009 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 2009 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 2009 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, 2008, 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
|
1,335,214
|
(1)
|
$ 23.95
|
(1)
|
2,564,107
|
(2)
|
||||
|
Equity
compensation plans not approved
|
||||||||||
|
by
security holders
|
-
|
-
|
-
|
|||||||
|
Total
|
1,335,214
|
$ 23.95
|
2,564,107
|
|||||||
|
(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 234,450 restricted units
approved by the board of directors’ Compensation Committee on February 11,
2009. In addition, on February 11, 2009, participants forfeited
56,905 shares related to awards measured during the three year performance
period ending December 31, 2008, and shares available for future
issue have been increased by that
amount.
|
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 and was reapproved at the 2006 annual meeting of
shareholders.
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 2009 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 2009 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, 2008, 2007, and 2006, 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
2008 – Accumulated provision for
|
|||||||||
|
uncollectible
accounts
|
$ 3.7
|
$ 16.9
|
$ 0.3
|
$ 15.3
|
$ 5.6
|
||||
|
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
2008 – Reserve for impaired
|
|||||||||
|
notes
receivable
|
$ 1.7
|
$ 4.6
|
$ -
|
$ -
|
$ 6.3
|
||||
|
Year
2007 – Reserve for impaired
|
|||||||||
|
notes
receivable
|
$ 1.6
|
$ 0.3
|
$ -
|
$ 0.2
|
$ 1.7
|
||||
|
Year
2006 – Reserve for impaired
|
|||||||||
|
notes
receivable
|
$ 3.4
|
$ 0.4
|
$ -
|
$ 2.2
|
$ 1.6
|
||||
|
OTHER
RESERVES:
|
|||||||||
|
Year
2008 – Restructuring costs
|
$ 0.6
|
$ -
|
$ -
|
$ -
|
$ 0.6
|
||||
|
Year
2007 – Restructuring costs
|
$ 1.7
|
$ -
|
$ -
|
$ 1.1
|
$ 0.6
|
||||
|
Year
2006 – Restructuring costs
|
$ 2.4
|
$ -
|
$ -
|
$ 0.7
|
$ 1.7
|
||||
List of
Exhibits
The
Company has incorporated by reference herein certain exhibits as specified below
pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the
Company attached to this filing filed electronically with the SEC are listed
below. Exhibits for the Company are listed in the Index to Exhibits
beginning on page 99.
Vectren
Corporation
Form
10-K
Attached
Exhibits
The
following Exhibits are included in this Annual Report on Form 10-K.
|
Exhibit
Number
|
Document
|
|
31.1
|
Chief
Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Chief
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
32
|
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
-102-
The
following Exhibits, as well as the Exhibits listed above, were filed
electronically with the SEC with this filing.
|
Exhibit
Number
|
Document
|
|
21.1
|
List
of Company’s Significant Subsidiaries
|
|
23.1
|
Consent
of Independent Registered Public Accounting Firm
|
|
23.2
|
Consent
of Independent Auditors
|
|
99.1
|
ProLiance
Holdings, LLC Consolidated Financial Statements
|
INDEX
TO EXHIBITS
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
|
Code
of By-Laws of Vectren Corporation as Most Recently Amended and Restated as
of February 27, 2008. (Filed and designated in Current Report
on Form 8-K filed February 27, 2008, File No. 1-15467, as Exhibit
3.1.)
|
|
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. (Filed and
designated in Form 8-K, dated October 16, 2006, File No. 1-16739, as
Exhibit 4.1). Sixth Supplemental Indenture, dated March 10,
2008, 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 National Association (Filed and designated in
Form 8-K, dated March 10, 2008, File No. 1-16739, as Exhibit
4.1)
|
|
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
|
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.)
|
|
10.4
|
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.)
|
|
10.5
|
Vectren
Corporation Nonqualified Deferred Compensation Plan, effective January 1,
2005. (Filed and designated in Form 8-K dated September 29,
2008, File No. 1-15467, as Exhibit
10.3.)
|
|
10.6
|
Vectren
Corporation Unfunded Supplemental Retirement Plan for a Select Group of
Management Employees (As Amended and Restated Effective January 1,
2005).(Filed and designated in Form 8-K dated December 17, 2008, File No.
1-15467, as Exhibit 10.1.)
|
|
10.7
|
Vectren
Corporation Nonqualified Defined Benefit Restoration Plan (As Amended and
Restated Effective January 1, 2005). (Filed and designated in Form 8-K
dated December 17, 2008, File No. 1-15467, as Exhibit
10.2.)
|
|
10.8
|
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.). Amendment Number One to the Vectren Corporation Change
in Control Agreement, effective as of March 1, 2005 between Vectren
Corporation and Niel C. Ellerbrook (Filed and designated in Form 8-K dated
September 29, 2008, File No. 1-15467, as Exhibit
10.1.)
|
|
10.9
|
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.)
|
| 10.10 |
Vectren
Corporation At Risk Compensation Plan specimen unit award agreement for
officers, effective January 1, 2009. (Filed and designated in
Form 8-K, dated February 17, 2009, File No. 1-15467, as Exhibit
10.1.)
|
|
10.11
|
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.)
|
| 10.12 | Vectren Corporation At Risk Compensation Plan specimen restricted stock units agreeement for officers, effective January 1, 2008. (Filed and designed in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.2.) |
|
10.13
|
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.)
|
|
10.14
|
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.) Amendment Number One
to the Specimen Vectren Corporation Employment Agreement between Vectren
Corporation and Executive Officers (Filed and designated in Form 8-K dated
September 29, 2008, File No. 1-15467, as Exhibit 10.2.) The specimen
agreements and related amendments differ among named executive officers
only to the extent severance and change in control benefits are
provided in the amount of three times base salary and bonus for Messrs.
Benkert, Chapman, and Christian and two times for Mr.
Doty.
|
|
10.15
|
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.)
|
|
10.16
|
Coal
Supply Agreement for Warrick 4 Generating Station between Southern Indiana
Gas and Electric Company and Vectren Fuels, Inc., effective January 1,
2009. (Filed and designated in Form 8-K dated January 5, 2009,
File No. 1-15467, as Exhibit 10.1.)
|
|
10.17
|
Coal
Supply Agreement for F.B. Culley Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., effective
January 1, 2009. (Filed and designated in Form 8-K dated
January 5, 2009, File No. 1-15467, as Exhibit
10.2.)
|
|
10.18
|
Coal
Supply Agreement for A.B. Brown Generating Station for 410,000 tons
between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc.,
effective January 1, 2009. (Filed and designated in Form 8-K
dated January 5, 2009, File No. 1-15467, as Exhibit
10.3.)
|
|
10.19
|
Coal
Supply Agreement for A.B. Brown Generating Station for 1 million tons
between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc.,
effective January 1, 2009. (Filed and designated in Form 8-K
dated January 5, 2009, File No. 1-15467, as Exhibit
10.4.)
|
|
10.20
|
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.)
|
|
10.21
|
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.)
|
|
|
|
|
10.22
|
Formation
Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC
Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group,
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.)
|
|
10.23
|
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among Vectren
Utility Holdings, Inc., and each of the purchasers named
therein. (Filed and designated in Form 10-K, for the year ended
December 31, 2005, File No. 1-15467, as Exhibit
10.24.)
|
|
10.24
|
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.)
|
|
10.25
|
Credit
Agreement (1 year facility), dated September 11, 2008, among Vectren
Capital Corp., as borrower, Vectren Corporation, as guarantor, the lenders
named therein, JPMorgan Chase Bank, N.A., and Union Bank of California,
N.A., as co-syndication agents, and Bank of America, N.A., as letter of
credit issuer and administrative agent. (Filed and designated in Form 8-K
dated September 11, 2008, File No. 1-15467, as Exhibit
10.1.)
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21.
Subsidiaries of the Company
23.
Consents of Experts and Counsel
The
consents of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 and 23.2. (Filed
herewith.)
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|
31.
Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of
2002
|
|
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32.
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
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-105-
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, 2009 /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.
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Signature
|
Title
|
Date
|
||
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/s/
Niel C. Ellerbrook
|
Chairman,
Chief Executive Officer, and Director
|
February
19, 2009
|
||
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Niel
C. Ellerbrook
|
(Principal
Executive Officer)
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|||
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/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President and Chief Financial
|
February
19, 2009
|
||
|
Jerome
A. Benkert, Jr.
|
Officer
(Principal
Financial Officer)
|
|||
|
/s/ M.
Susan Hardwick
|
Vice
President, Controller and Assistant Treasurer
|
February
19, 2009
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
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/s/
John M. Dunn
|
Director
|
February
19, 2009
|
||
|
John
M. Dunn
|
||||
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/s/
John D. Engelbrecht
|
Director
|
February
19, 2009
|
||
|
John
D. Engelbrecht
|
||||
|
/s/
Anton H. George
|
Director
|
February
19, 2009
|
||
|
Anton
H. George
|
||||
|
/s/
Martin C. Jischke
|
Director
|
February
19, 2009
|
||
|
Martin
C. Jischke
|
||||
|
/s/
Robert L. Koch II
|
Director
|
February
19, 2009
|
||
|
Robert
L. Koch II
|
||||
|
/s/
William G Mays
|
Director
|
February
19, 2009
|
||
|
William
G. Mays
|
||||
|
/s/
J. Timothy McGinley
|
Director
|
February
19, 2009
|
||
|
J.
Timothy McGinley
|
||||
|
/s/
Richard P. Rechter
|
Director
|
February
19, 2009
|
||
|
Richard
P. Rechter
|
||||
|
/s/
R. Daniel Sadlier
|
Director
|
February
19, 2009
|
||
|
R.
Daniel Sadlier
|
||||
|
/s/
Richard W. Shymanski
|
Director
|
February
19, 2009
|
||
|
Richard
W. Shymanski
|
||||
|
/s/
Michael L Smith
|
Director
|
February
19, 2009
|
||
|
Michael
L Smith
|
||||
|
/s/
Jean L. Wojtowicz
|
Director
|
February
19, 2009
|
||
|
Jean
L. Wojtowicz
|