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, 2009
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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|
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(State
or other jurisdiction of incorporation or organization)
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(IRS
Employer Identification No.)
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One
Vectren Square
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47708
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|
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant's
telephone number, including area code: 812-491-4000
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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|
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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 whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files). Yes □ 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, 2009, was $1,889,960,254.
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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81,152,870
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January 31, 2010
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|
Class
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Number
of Shares
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Date
|
Documents
Incorporated by Reference
Certain
information in the Company's definitive Proxy Statement for the 2010 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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MISO:
Midwest Independent System Operator
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ASC: Accounting
Standards Codification
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MW: megawatts
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BTU
/ MMBTU: British thermal units / millions of
BTU
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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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NERC: North
American Electric Reliability Corporation
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FERC: Federal
Energy Regulatory Commission
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OCC: Ohio
Office of the Consumer Counselor
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IDEM: Indiana
Department of Environmental Management
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OUCC: Indiana
Office of the Utility Consumer Counselor
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IURC: Indiana
Utility Regulatory Commission
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PUCO: Public
Utilities Commission of Ohio
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IRC: Internal
Revenue Code
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USEPA: United
States Environmental Protection Agency
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MCF
/ BCF: thousands / billions of cubic feet
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Throughput: combined
gas sales and gas transportation volumes
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MDth
/ MMDth: thousands / millions of dekatherms
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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
|
||
-3-
Table
of Contents
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 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. 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 567,000 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 assets 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 315,000 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, 2009, the
Company had $4.7 billion in total assets, with $3.8 billion (82 percent)
attributed to the Utility Group and $0.8 billion (18 percent) attributed to the
Nonutility Group. Net income for the year ended December 31, 2009,
was $133.1 million, or $1.65 per share of common stock, with net income of
$107.4 million attributed to the Utility Group, $25.8 million attributed to the
Nonutility Group, and a net loss of $0.1 million attributed to Corporate and
Other. Excluding the impact of a charge recorded in 2009 discussed in
Note 5 in the Company’s Consolidated Financial Statements included under “Item 8
Financial Statements and Supplementary Data” totaling $11.9 million after tax,
or $0.15 per share, related to ProLiance Holdings, LLC’s (ProLiance) investment
in Liberty Gas Storage, for the year ended December 31, 2009, there was
consolidated net income of $145.0 million, or $1.80 per share. Net income for
the year ended December 31, 2008, was $129.0 million, or $1.65 per share of
common stock. For further information regarding the activities and
assets of operating segments within these Groups, refer to Note 19 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
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, 2009, the Company supplied natural gas service to approximately
993,100 Indiana and Ohio customers, including 907,500 residential, 84,000
commercial, and 1,600 industrial and other contract
customers. Average gas utility customers served were approximately
981,300 in 2009 and 986,700 in both 2008 and 2007.
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
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 throughput was 184.5 MMDth for the year ended
December 31, 2009. Gas sold and transported to residential and
commercial customers was 106.5 MMDth representing 58 percent of
throughput. Gas transported or sold to industrial and other contract
customers was 78.0 MMDth representing 42 percent of throughput. Rates
for transporting gas generally provide for the same margins earned by selling
gas under applicable sales tariffs.
For the
year ended December 31, 2009, gas utility revenues were approximately $1,066.0
million, of which residential customers accounted for 68 percent and commercial
26 percent. Industrial and other contract customers account for only 6 percent
of revenues due to the high number of transportation customers in that customer
class.
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 5 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 approved the first
two phases of a three phase plan to exit the merchant function in the
Company’s Ohio service territory.
The
initial phase of the plan was implemented on October 1, 2008 and continues
through March 31, 2010. During the initial phase, wholesale suppliers that
were winning bidders in a PUCO approved auction provide the gas commodity to
VEDO for resale to its residential and general service 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
(one of which is Vectren Retail, LLC, a wholly owned subsidiary of Vectren)
essentially on demand. This method of purchasing gas eliminated the need
for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits.
The
second phase of the exit process begins on April 1, 2010, during which the
Company will no longer sell natural gas directly to these
customers. Rather, state-certified Competitive Retail Natural Gas
Suppliers, that are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers for 12 months at
auction-determined standard pricing. That auction was conducted on
January 12, 2010, and the auction results were approved by the PUCO on January
13. The plan approved by the PUCO requires that the Company conduct at
least two auctions during this phase. As such, the Company will conduct
another auction in advance of the second 12-month term, which will commence on
April 1, 2011. Consistent with current practice, customers will
continue to receive one bill for the delivery of natural gas
service.
In the
last phase, which was not approved in the April 2008 order, it is contemplated
that all of the Company’s Ohio residential and general service 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 phases of
the transition, which allows the Company to recover costs associated with the
transition, and it is anticipated this rider will remain in effect throughout
the entire transition. Since the cost of gas is currently passed
through to customers during phase one and two 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 2009,
Utility Holdings purchased 97,682 MDth volumes of gas at an average cost of
$5.97 per Dth, of which approximately 76 percent was purchased from ProLiance, 4
percent was purchased from Vectren Retail, LLC (d/b/a Vectren Source), as
discussed above, and 20 percent was purchased from third party
providers. The average cost of gas per Dth purchased for the previous
four years was $9.61 in 2008, $8.14 in 2007, $8.64 in 2006, and $9.05 in
2005.
Electric
Utility Services
At
December 31, 2009, the Company supplied electric service to approximately
141,400 Indiana customers, including approximately 122,900 residential, 18,400
commercial, and 100 industrial and other customers. Average electric
utility customers served were approximately 140,900 in 2009; 141,100 in 2008;
and 140,800 in 2007.
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, 2009, retail electricity sales totaled 5,039.7 GWh,
resulting in revenues of approximately $493.2 million. Residential
customers accounted for 37 percent of 2009 revenues; commercial 28 percent;
industrial 33 percent, and other 2 percent. In addition, in 2009 the
Company sold 603.6 GWh through wholesale activities principally to the
MISO. Wholesale revenues, including transmission-related revenue,
totaled $35.4 million in 2009.
System
Load
Total
load for each of the years 2005 through 2009 at the time of the system summer
peak, and the related reserve margin, is presented below in MW. The
peak loads in 2009 reflect the current weak industrial demand and mild
weather.
|
Date
of summer peak load
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6/22/2009
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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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|||||
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Total
load at peak (1)
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1,143
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1,242
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1,341
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1,325
|
1,315
|
|||||
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Generating
capability
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1,295
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1,295
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1,295
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1,351
|
1,351
|
|||||
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Firm
purchase supply
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136
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135
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130
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107
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107
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|||||
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Interruptible
contracts & direct load control
|
62
|
62
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62
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62
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76
|
|||||
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Total
power supply capacity
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1,493
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1,492
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1,487
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1,520
|
1,534
|
|||||
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Reserve
margin at peak
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31%
|
20%
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11%
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15%
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17%
|
|
(1)
|
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 2009 the Summer Cycler
program was not activated.
|
The winter peak load for the 2008-2009 season of approximately 883 MW occurred on January 15, 2009. The prior year winter peak load was approximately 960 MW, occurring on January 25, 2008.
Generating
Capability
Installed
generating capacity as of December 31, 2009, was rated at 1,298
MW. Coal-fired generating units provide 1,000 MW of capacity, natural
gas or oil-fired turbines used for peaking or emergency conditions provide 295
MW, and in 2009 SIGECO purchased a landfill gas electric generation project
which provides 3 MW. Electric generation for 2009 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 4,657 GWh in 2009. 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. (Vectren Fuels), a
wholly owned subsidiary of the Company. Approximately 2.8 million
tons were purchased for generating electricity during 2009, of which
approximately 86 percent was supplied by Vectren Fuels from its mines and third
party purchases. The average cost of coal paid by the utility in
generating electric energy for the years 2005 through 2009 follows:
|
Year
Ended December 31,
|
||||||||||||||||||||
|
Average
Delivered
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2009
|
2008
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2007
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2006
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2005
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|||||||||||||||
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Cost per
Ton
|
$ | 61.67 | $ | 42.50 | $ | 40.23 | $ | 37.51 | $ | 30.27 | ||||||||||
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Cost per
MWh
|
30.09 | 20.84 | 19.78 | 18.44 | 14.94 | |||||||||||||||
As of January 1, 2009, SIGECO purchases coal from Vectren Fuels under new coal purchase agreements. The term of these coal purchase agreements continues to December 31, 2014, with prices specified originally ranging from two to four years. New pricing reflects Illinois Basin market prices in effect when the contracts were executed and have resulted in higher costs compared to prior years.
The
utility purchased approximately 13.3 percent less coal in 2009 compared to
2008. Due to contractual obligations, its year end coal inventory
rose to approximately 1.1 million tons, compared to 0.5 million tons at the end
of 2008.
Firm Purchase
Supply
The
Company has 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 can 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. The Company’s 1.5 percent interest in OVEC makes available
approximately 30 MW of capacity. The Company purchased approximately
211 GWh from OVEC in 2009.
The
Company had 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 expired on December 31, 2009 and was
not renewed. The Company purchased insignificant amounts under this
contract in 2009.
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, with the approval of the IURC. The contract expires in
2029. In 2009, the Company purchased approximately 91 GWh under this
contract; however, none was purchased at the time of peak load on June 22,
2009.
In
December 2009, the Company executed a 20 year power
purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50
MW of energy from a wind farm located in Benton and Tippecanoe Counties in
Indiana, with the approval of the IURC. The Company purchased
insignificant amounts under this contract in 2009.
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 2009 totaled
855 GWh.
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 600 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, 2009, over
117,000 customers in Vectren’s Ohio service territory purchase natural gas from
a supplier other than VEDO. 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,
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. The Company, including its
retail gas supply operations, contracted for approximately 75 percent of its
natural gas purchases through ProLiance in 2009.
For the
year ended December 31, 2009, ProLiance’s revenues, including sales to Vectren
companies, were $1.7 billion, compared to $2.9 billion in 2008 and $2.3 billion
in 2007. ProLiance’s audited financial statements as of and for its
fiscal years ending September 30, 2009, 2008, and 2007, are included as Exhibit
99.1 to this Form 10-K.
Vectren
Source
As of
December 31, 2009, Vectren Source provided natural gas and other related
products and services in the Midwest and Northeast United States to over 189,000
equivalent residential and commercial customers. This customer base
reflects approximately 62,000 of VEDO’s customers that have voluntarily opted to
choose their natural gas supplier and the supply of natural gas to nearly 33,000
equivalent customers in VEDO’s service territory as part of VEDO’s process of
exiting the merchant function, which began October 1, 2008. Vectren
Source generated approximately $157.2 million in revenues for 2009 compared to
$182.6 million in 2008 and $168.3 million in 2007. Gas sold
approximated 18,457 MDth in 2009; 16,210 MDth in 2008; and 13,543 MDth in
2007. Average equivalent customers served by Vectren Source were
179,000 in 2009; 157,000 in 2008; and 154,000 in 2007.
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. In 2009, 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, Vectren Fuels announced plans to open two new underground
mines. The first of two new underground mines located near Vincennes,
Indiana, which began minor coal extraction in the latter half of 2009, is
now operational. The second mine is currently expected to open in
2011. However, Vectren Fuels may continue to change this time table as it
evaluates the impacts of current coal market conditions. Reserves at the
two mines are estimated at about 100 million tons of recoverable number-five
coal at 11,200 BTU and less than 6-pound sulfur dioxide. Once in
production, the two new mines are capable of producing about 5 million tons of
coal per year. Management expects to incur approximately $200 million to
access the coal reserves. Of the total $200 million expected investment,
the Company has invested $174 million through December 31, 2009, inclusive of
$46 million in land and buildings, $118 million in mine development and
equipment, and $10 million in advanced royalty payments.
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 both mines. Access to the Oaktown 1 mine
was accomplished via a 90 foot deep box cut and a 2,200 foot slope on a 14
percent grade, reaching coal in excess of 375 feet below the
surface. Access to the Oaktown 2 mine is planned via an 80 foot deep
box cut and a 2,600 foot slope on a 14 percent grade, reaching coal in excess of
400 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 coal 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, which is currently
under construction. The mine is connected to a railway 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 to
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 $175 million. Through December 31,
2009, approximately 7,500 acres of coal have been mined with approximately
10,400 acres remaining. Reserves at December 31, 2009 approximate 35 million
tons, not including possible nearby expansion opportunities. The
remaining unamortized plant balance as of December 31, 2009 approximates $81
million, inclusive of $3 million of land and buildings and $78 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, 2009, no
significant reserves remain. The remaining unamortized plant balance
as of December 31, 2009 approximates $7 million, inclusive of $1 million of land
and buildings and $6 million in 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)
|
||||||||||
|
2009
|
969
|
2,583
|
-
|
-
|
3,552
|
|||||
|
2008
|
1,150
|
2,378
|
-
|
-
|
3,528
|
|||||
|
2007
|
1,433
|
2,632
|
-
|
-
|
4,065
|
|||||
|
County
Located in Indiana
|
Warrick
|
Pike
|
Knox
|
Knox
|
||||||
|
Coal
Reserves (thousands of tons)
|
-
|
34,800
|
62,400
|
38,800
|
136,000
|
|||||
|
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
Pipeline
Effective
July 1, 2006, the Company purchased the remaining 50 percent of Miller from 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. Miller’s customers include Vectren’s
utilities.
Energy Systems
Group
Performance-based
energy contracting operations and renewable energy services are performed
through 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 and electricity. During
2009, SIGECO purchased one such project with IURC approval. 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, 2009, 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.
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. received processing fees from synfuel producers unrelated to
Pace Carbon for a portion of its coal production. These synfuel related
credits and fees ended on December 31, 2007 when tax laws
expired. 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.
Personnel
As of
December 31, 2009, 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
October 2009, the Company’s existing agreement expired with Local 175 of the
Utility Workers Union of America. Employees continue to work without
a contractual agreement and continue the negotiation process.
In
September 2009, the Company reached a three year agreement with Local 135 of the
Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September
2012.
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.
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
through 2011.
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. Despite
the beginning of recovery, the consequences of the recent recession may continue
to result in 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 continue to be accompanied by a decrease in demand for natural gas
and electricity. The recent recession may continue to have some
negative impact on both gas and electric large customers and wholesale power
sales. This impact may continue to include tempered growth,
significant conservation measures, and perhaps even further plant closures or
bankruptcies. Deteriorating economic conditions may also continue to
lead to further reductions in residential and commercial customer counts, lower
Company revenues, and increasing coal inventories. It is also
possible that a weak economy could continue and further affect costs including
pension costs, interest costs, and uncollectible accounts expense.
Further,
the Company’s nonutility portfolio may also be negatively impacted if a weak
economy continues. 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
recession may continue to 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
if the recession continues, there could be 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 12 percent of electric utility margin, 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 level 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-2
|
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 phase 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 electric utility sales are space heating and
cooling. Accordingly, its operating results may fluctuate with
variability of weather.
Vectren’s
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 mitigates most 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, the USEPA, 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 rates 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
rates of return.
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 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 regulation could negatively impact operations.
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, nonutility coal mining
operations, and 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 with
regard to operating expenses for the purchase of allowances, and later for
capital expenditures as technology becomes available to control greenhouse gas
emissions. However, these compliance cost estimates are based on
highly uncertain assumptions, including allowance prices and energy efficiency
targets.
Any
additional expenses or capital incurred by the Company, as it relates to
complying with greenhouse gas emissions regulation or other environmental
regulations, are expected to be borne by the customers in its service
territories through increased rates. Increased rates have an impact
on the economic health of the communities served. New regulations
could also negatively impact industries in the Company’s service territory,
including industries in which the Company operates.
The
Company is exposed to physical and financial risks related to the uncertainty of
climate change.
A
changing climate creates uncertainty and could result in broad changes to the
Company’s service territories. These impacts could include, but are
not limited to, population shifts; changes in the level of annual rainfall;
changes in the weather; and changes to the frequency and severity of weather
events such as thunderstorms, wind, tornadoes, and ice storms that can damage
infrastructure. Such changes could impact the Company in a number of
ways including the number and/or type of customers in the Company’s service
territories; the demand for energy resulting in the need for additional
investment in generation assets or the need to retire current infrastructure
that is no longer required; an increase to the cost of providing service; and an
increase in the likelihood of capital expenditures to replace damaged
infrastructure.
To the
extent climate change impacts a region’s economic health, it may also impact the
Company’s revenues, costs, and capital structure and thus the need for changes
to rates charged to regulated customers. Rate changes themselves can
impact the economic health of the communities served and may in turn adversely
affect the Company’s operating results.
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. Presently, 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 commodity prices, 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.
Coal
mining operations could be adversely affected by a number of
factors.
The
success of coal mining operations is predicated on the ability to fully access
coal at two new company-owned mines; to operate owned mines in accordance with
Mine Safety and Health Administration (MSHA) guidelines and recent
interpretations of those guidelines; to negotiate and execute new sales
contracts; and to manage production and production costs and other risks in
response to changes in demand. Other risks, which could adversely
impact operating results, include but are not limited to: market
demand for coal; geologic, equipment, and operational risks; 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’s
subsidiaries have performance and warranty obligations, some of which are
guaranteed by Vectren Corporation.
In the
normal course of business, subsidiaries of Vectren issue performance bonds and
other forms of assurance that commit them to timely install infrastructure,
operate facilities, pay vendors or subcontractors, and/or support warranty
obligations. Vectren Corporation, as the parent company, will from
time to time guarantee its subsidiaries’ commitments. These
guarantees do not represent incremental consolidated obligations; rather, they
represent parental guarantees of subsidiary obligations in order to allow those
subsidiaries the flexibility to conduct business without posting other forms of
collateral. The Company has not been called upon to satisfy any
obligations pursuant to these parental guarantees.
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 16.7 BCF
of interstate pipeline storage service with a maximum peak day delivery
capability of 252,600 MMBTU per day. Indiana Gas’ gas delivery system
includes 13,000 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
interstate pipeline storage 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, 2009, was rated at 1,298
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. In
2009, SIGECO purchased a landfill gas electric generation project in Pike
County, Indiana with a total capability of 3 MW.
SIGECO's
transmission system consists of 932 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 34 substations with an
installed capacity of 4,500 megavolt amperes (Mva). The electric
distribution system includes 4,200 pole miles of lower voltage overhead lines
and 358 trench miles of conduit containing 2,000 miles of underground
distribution cable. The distribution system also includes 97
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 and audits and reviews by taxing
authorities and other government agencies arising in the normal course of
business. In the opinion of management, there are no legal
proceedings or other regulatory reviews or audits 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, and rate and regulatory matters. The
consolidated condensed 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 2009 and 2008, 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
|
||||||||||
|
2009
|
||||||||||||
|
First
Quarter
|
$ | 0.335 | $ | 26.90 | $ | 18.08 | ||||||
|
Second
Quarter
|
0.335 | 24.06 | 19.72 | |||||||||
|
Third
Quarter
|
0.335 | 25.33 | 22.47 | |||||||||
|
Fourth
Quarter
|
0.340 | 25.50 | 21.99 | |||||||||
|
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 | |||||||||
On
February 3, 2010 the board of directors declared a dividend of $0.340 per share,
payable on March 1, 2010, to common shareholders of record on February 16,
2010.
As of
January 31, 2010, there were 9,611 shareholders registered of the Company’s
common stock.
Quarterly Share
Purchases
Periodically,
the Company purchases shares from the open market to satisfy share requirements
associated with the Company’s share-based compensation plans; however, no such
open market purchases were made during the quarter ended December 31,
2009.
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 50 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 dividend payments, 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)
|
2009 1/ | 2008 | 2007 | 2006 | 2005 | |||||||||||||||
|
Operating
Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 2,088.9 | $ | 2,484.7 | $ | 2,281.9 | $ | 2,041.6 | $ | 2,028.0 | ||||||||||
|
Operating
income
|
$ | 280.1 | $ | 263.4 | $ | 260.5 | $ | 220.5 | $ | 213.1 | ||||||||||
|
Net
income
|
$ | 133.1 | $ | 129.0 | $ | 143.1 | $ | 108.8 | $ | 136.8 | ||||||||||
|
Average
common shares outstanding
|
80.7 | 78.3 | 75.9 | 75.7 | 75.6 | |||||||||||||||
|
Fully
diluted common shares outstanding
|
81.0 | 78.9 | 76.6 | 76.2 | 76.1 | |||||||||||||||
|
Basic
earnings per share
|
||||||||||||||||||||
|
on
common stock
|
$ | 1.65 | $ | 1.65 | $ | 1.89 | $ | 1.44 | $ | 1.81 | ||||||||||
|
Diluted
earnings per share
|
||||||||||||||||||||
|
on
common stock
|
$ | 1.64 | $ | 1.63 | $ | 1.87 | $ | 1.43 | $ | 1.80 | ||||||||||
|
Dividends
per share on common stock
|
$ | 1.345 | $ | 1.310 | $ | 1.270 | $ | 1.230 | $ | 1.190 | ||||||||||
|
Balance
Sheet Data:
|
||||||||||||||||||||
|
Total
assets
|
$ | 4,671.8 | $ | 4,632.9 | $ | 4,296.4 | $ | 4,091.6 | $ | 3,868.1 | ||||||||||
|
Long-term
debt, net
|
$ | 1,540.5 | $ | 1,247.9 | $ | 1,245.4 | $ | 1,208.0 | $ | 1,198.0 | ||||||||||
|
Common
shareholders' equity
|
$ | 1,397.2 | $ | 1,351.6 | $ | 1,233.7 | $ | 1,174.2 | $ | 1,143.3 | ||||||||||
1/ The
net income during the year ended December 31, 2009 includes the impact of a
charge discussed in Note 5 in the Company’s Consolidated Financial Statements
included under “Item 8 Financial Statements and Supplementary Data” totaling
$11.9 million after tax, or $0.15 per share, related to ProLiance’s investment
in Liberty Gas Storage. Excluding this charge, there was consolidated
net income of $145.0 million, or $1.80 per share in 2009.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
Executive
Summary of Consolidated Results of Operations
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 and other operations. Primary nonutility operations denote
areas of management’s forward looking focus.
The
Utility Group generates revenue primarily from the delivery of natural gas and
electric service to its customers. The primary source of cash flow for the
Utility Group results from the collection of customer bills and the payment for
goods and services procured for the delivery of gas and electric services.
The activities of and revenues and cash flows generated by the Nonutility Group
are closely linked to the utility industry, and the results of those operations
are generally impacted by factors similar to those impacting the overall utility
industry. In addition, there are other operations, referred to herein
as Corporate and Other, that include unallocated corporate expenses such as
advertising and charitable contributions, among other activities.
The
Company has in place a disclosure committee that consists of senior management
as well as financial management. The committee is actively involved
in the preparation and review of the Company’s SEC filings.
For the
year ended December 31, 2009, consolidated net income was $133.1 million, or
$1.65 per share, compared to earnings of $129.0 million, or $1.65 per share, in
2008 and $143.1 million, or $1.89 per share, in 2007. Excluding the
impact of a charge recorded in 2009 discussed below totaling $11.9 million after
tax, or $0.15 per share, related to ProLiance’s investment in Liberty Gas
Storage, for the year ended December 31, 2009, consolidated net income was
$145.0 million, or $1.80 per share.
Utility
Group results were down only modestly in 2009, even after considering the
impacts of the recession; significant cost reductions helped offset those
impacts to a large degree. The Nonutility Group showed significantly
improved performance, particularly in coal mining and retail gas marketing
businesses.
2009
Charge Related to Liberty Gas Storage
During
the second quarter of 2009, the Company recorded its share of the charge related
to ProLiance’s investment in Liberty Gas Storage, LLC (herein referred to as the
Liberty Charge). In the Consolidated Statement of Income
for the year ended December 31, 2009, the impact associated with the
Liberty Charge is an approximate $19.9 million reduction to Equity in earnings of unconsolidated
affiliates and an income tax benefit reflected in Income taxes of approximately
$8.0 million. The $11.9 million after tax, or $0.15 per share, charge is
consistent with previous disclosures about development issues at the Louisiana
site made in the prior year’s annual report. More detailed
information about ProLiance’s investment in Liberty is included in Note 5 to the
consolidated financial statements.
Consolidated
Results Excluding the Liberty Charge (See Page 42, Regarding the Use of Non-GAAP
Measures)
Net
income and earnings per share, excluding the Liberty Charge, in total and by
group, for the years ended December 31, 2009, 2008, and 2007
follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share data)
|
2009
|
2008
|
2007
|
|||||||||
|
Net
income, excluding Liberty Charge
|
$ | 145.0 | $ | 129.0 | $ | 143.1 | ||||||
|
Attributed
to:
|
||||||||||||
|
Utility
Group
|
$ | 107.4 | $ | 111.1 | $ | 106.5 | ||||||
|
Nonutility
Group, excluding Liberty Charge
|
37.7 | 18.9 | 37.0 | |||||||||
|
Corporate
& Other
|
(0.1 | ) | (1.0 | ) | (0.4 | ) | ||||||
|
Basic
earnings per share, excluding Liberty Charge
|
$ | 1.80 | $ | 1.65 | $ | 1.89 | ||||||
|
Attributed
to:
|
||||||||||||
|
Utility
Group
|
$ | 1.33 | $ | 1.42 | $ | 1.40 | ||||||
|
Nonutility
Group, excluding Liberty Charge
|
0.47 | 0.24 | 0.49 | |||||||||
|
Corporate
& Other
|
- | (0.01 | ) | - | ||||||||
Utility
Group
In 2009,
the Utility Group’s earnings were $107.4 million, compared to earnings of $111.1
million in 2008 and $106.5 million in 2007. The decrease in 2009
compared to 2008 reflects lower large customer usage and lower wholesale power
sales, both due to the recession, mild cooling weather, and an increase in
depreciation expense associated with rate base growth. Increased
revenues associated with regulatory initiatives, lower operating expenses, and
the return of market values associated with investments related benefit plans
partially offset these declines.
In 2008
compared to 2007, the Utility Group earnings increased due primarily to a full
year of base rate increases 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 the
Company’s electric and the Ohio natural gas service territory, which was not
fully protected by straight fixed variable rate design in 2009, management
estimates the margin impact of weather to be approximately $5.4 million
unfavorable or $0.04 per share compared to normal temperatures. In
2008, management estimates a $1.2 million favorable impact on margin compared to
normal or $0.01 per share, and in 2007 a $5.5 million favorable impact on margin
compared to normal or $0.04 per share.
Nonutility
Group
In 2009,
Nonutility Group earnings, excluding the Liberty Charge, were $37.7 million,
compared to net income of $18.9 million 2008 and $37.0 million in
2007. Inclusive of the Liberty Charge, 2009 Nonutility Group earnings
were $25.8 million.
The 2009
improvement of $18.8 million compared to 2008 primarily reflects a $15.4 million
increase in earnings from primary nonutility operations. Primary
nonutility business groups are Energy Marketing and Services, Coal Mining, and
Energy Infrastructure Services companies. Coal mining operations has
shown improvement due to increased pricing effective January 1, 2009, increasing
its contribution to earnings approximately $18.0 million. Retail gas
marketing earnings are $4.5 million higher than the prior year, and performance
contracting activity at ESG increased its earnings contribution $2.1 million
compared to 2008. These increases were partially offset by lower
earnings contributions from ProLiance and Miller Pipeline.
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 a FERC
matter. In addition, the results from the other primary nonutility
operations reflect increased earnings from performance contracting and renewable
energy construction operations performed through ESG and retail gas marketing
operations performed through Vectren Source. Miller’s results were
generally flat compared to 2007.
Other
nonutility businesses operated at a loss of $2.5 million in 2009, compared to a
loss of $5.9 million in 2008 and earnings of $0.3 million in
2007. Other nonutility businesses are legacy investments, including
investments in commercial real estate. The lower results in 2008 were
driven primarily by a charge associated with commercial real estate investments
totaling $10.0 million, $5.9 million after tax, or $0.08 per share.
In 2007,
the last year of synfuel operations, synfuel-related results generated earnings
of $6.8 million. Of those earnings, $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. The Foundation contribution is included in Other operating expenses in
the Consolidated Statements of
Income.
Dividends
Dividends
declared for the year ended December 31, 2009 were $1.345 per share compared to
$1.310 in 2008 and $1.270 per share in 2007. In October 2009, the
Company’s board of directors increased its quarterly dividend to $0.340 per
share from $0.335 per share. The increase marks the 50th
consecutive year Vectren and predecessor companies’ have increased annual
dividends paid.
Impacts
of Share Issuance in 2008
The
increased number of common shares outstanding, resulting from the issuance of
common shares in 2008, contributed a $0.04 reduction in earnings per share in
2009 compared to 2008 and in 2008 compared to 2007.
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, 2009, 2008, and 2007, follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share data)
|
2009
|
2008
|
2007
|
|||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Electric
utility
|
528.6 | 524.2 | 487.9 | |||||||||
|
Other
|
1.6 | 1.8 | 1.7 | |||||||||
|
Total
operating revenues
|
1,596.2 | 1,958.7 | 1,759.0 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost of gas
sold
|
618.1 | 983.1 | 847.2 | |||||||||
|
Cost of fuel &
purchased power
|
194.3 | 182.9 | 174.8 | |||||||||
|
Other
operating
|
304.6 | 300.3 | 266.1 | |||||||||
|
Depreciation &
amortization
|
180.9 | 165.5 | 158.4 | |||||||||
|
Taxes other than
income taxes
|
60.3 | 72.3 | 68.1 | |||||||||
|
Total
operating expenses
|
1,358.2 | 1,704.1 | 1,514.6 | |||||||||
|
OPERATING
INCOME
|
238.0 | 254.6 | 244.4 | |||||||||
|
Other
income - net
|
7.8 | 4.0 | 9.4 | |||||||||
|
Interest
expense
|
79.2 | 79.9 | 80.6 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
166.6 | 178.7 | 173.2 | |||||||||
|
Income
taxes
|
59.2 | 67.6 | 66.7 | |||||||||
|
NET
INCOME
|
$ | 107.4 | $ | 111.1 | $ | 106.5 | ||||||
|
CONTRIBUTION
TO VECTREN BASIC EPS
|
$ | 1.33 | $ | 1.42 | $ | 1.40 | ||||||
Trends in Utility Operations
Utility Group
Margin
Throughout
this discussion, the terms Gas Utility margin and Electric Utility margin are
used. Gas Utility margin is calculated as Gas utility revenues less the
Cost of gas
sold. Electric Utility margin is calculated as Electric utility revenues
less 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 and purchased power costs can be volatile and are
generally collected on a dollar-for-dollar basis from customers.
Rate
Design Strategies
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 been volatile. 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 2006. SIGECO’s natural
gas territory has an NTA since 2005 and lost margin recovery since 2007.
The Ohio service territory had lost margin recovery since 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 monthly service charge revenues and less dependent on volumetric
revenues than previous rate designs. This new rate design, which will be fully
implemented in February 2010, will mitigate most weather risk in
Ohio. SIGECO’s electric service territory has neither NTA nor lost
margin recovery mechanisms; however, rate designs proposed in a recently filed
rate case requests a lost margin recovery mechanism that works in tandem with
conservation initiatives, similar to rate designs undertaken in the Indiana gas
service territories.
Tracked
Operating Expenses
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 uncollectible accounts expense and
percent of income payment plan expenses, costs associated with exiting the
merchant function and to perform service riser replacement in Ohio, Indiana gas
pipeline integrity management costs, costs to fund Indiana energy efficiency
programs, MISO transmission revenues and costs, as well as the gas cost
component of uncollectible accounts expense based on historical experience and
unaccounted for gas. Unaccounted for gas is also tracked in the Ohio
service territory. Certain operating costs, including depreciation,
associated with operating environmental compliance equipment at electric
generation facilities and regional electric transmission investments are also
tracked.
Recessionary
Impacts
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 has had and may continue to have some negative impact on sales
to and usage by both gas and electric large customers. This impact
has included, and may continue to include, tempered growth, significant
conservation measures, and increased plant closures and
bankruptcies. While no one industrial customer comprises 10 percent
of consolidated revenues, the top five industrial electric customers comprise
approximately 12 percent of electric utility margin for the year ended December
31, 2009, and therefore any significant decline in their collective margin could
adversely impact operating results. Deteriorating economic conditions
may also lead to continued lower residential and commercial customer
counts. Further, resulting from the lower power prices, decreased
demand for electricity and higher coal prices associated with contracts
negotiated last year, the Company’s coal fired generation has been dispatched
less often by the MISO. This has resulted in lower wholesale sales,
more power being purchased from the MISO for native load requirements, and
larger coal inventories.
Following
is a discussion and analysis of margin generated from regulated utility
operations.
Gas
Utility Margin (Gas utility revenues less Cost of gas sold)
Gas
utility margin and throughput by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Gas
utility revenues
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Cost
of gas sold
|
618.1 | 983.1 | 847.2 | |||||||||
|
Total
gas utility margin
|
$ | 447.9 | $ | 449.6 | $ | 422.2 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 388.8 | $ | 385.5 | $ | 360.9 | ||||||
|
Industrial
customers
|
46.8 | 51.2 | 48.7 | |||||||||
|
Other
|
12.3 | 12.9 | 12.6 | |||||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
106.5 | 114.8 | 108.4 | |||||||||
|
Industrial
customers
|
78.0 | 91.5 | 86.2 | |||||||||
|
Total
sold & transported volumes
|
184.5 | 206.3 | 194.6 | |||||||||
For the
year ended December 31, 2009, gas utility margins were $447.9 million, a slight
decrease of $1.7 million, compared to 2008. Management estimates a
$4.4 million year over year decrease in industrial customer margin associated
with lower volumes sold, and slightly lower residential and commercial customer
counts decreased margin approximately $1.7 million. These
recessionary impacts were offset by margin associated with regulatory
initiatives. Among all customer classes, margin increases associated
with regulatory initiatives, including the full impact of the Vectren North base
rate increase effective in February 2008 and the Vectren Ohio base rate increase
effective February 2009, were $8.4 million year over year. The impact
of operating costs, including revenue and usage taxes, recovered in margin was
unfavorable $2.9 million year over year, reflecting lower revenue taxes offset
by higher pass through operating expenses. The remaining decrease
primarily relates to Ohio weather and lower miscellaneous revenues associated
with reconnection fees. The lower fees as well as the lower revenue
and usage taxes correlate with lower year over year gas costs. The
average cost per dekatherm of gas purchased during 2009 was $5.97 compared to
$9.61 in 2008 and $8.14 in 2007.
For the
year ended December 31, 2008, gas utility margins increased $27.4 million
compared to 2007. Regulatory initiatives, including the Vectren North
base rate increase, effective February 2008 and the Vectren South base rate case
effective August 2007, added $15.4 million in margin. 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, recovered
in margin, increased gas margin $7.8 million.
Electric
Utility Margin (Electric utility revenues less Cost of fuel & purchased
power)
Electric
utility margin and volumes sold by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Electric
utility revenues
|
$ | 528.6 | $ | 524.2 | $ | 487.9 | ||||||
|
Cost
of fuel & purchased power
|
194.3 | 182.9 | 174.8 | |||||||||
|
Total
electric utility margin
|
$ | 334.3 | $ | 341.3 | $ | 313.1 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 221.9 | $ | 218.6 | $ | 198.6 | ||||||
|
Industrial
customers
|
84.5 | 82.9 | 78.3 | |||||||||
|
Municipals
& other customers
|
7.2 | 7.3 | 15.3 | |||||||||
|
Subtotal:
Retail
|
$ | 313.6 | $ | 308.8 | $ | 292.2 | ||||||
|
Wholesale
margin
|
20.7 | 32.5 | 20.9 | |||||||||
|
Total
electric utility margin
|
$ | 334.3 | $ | 341.3 | $ | 313.1 | ||||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
2,760.8 | 2,850.5 | 3,042.9 | |||||||||
|
Industrial
customers
|
2,258.9 | 2,409.1 | 2,538.5 | |||||||||
|
Municipals
& other
|
20.0 | 63.8 | 635.1 | |||||||||
|
Total
retail & firm wholesale volumes sold
|
5,039.7 | 5,323.4 | 6,216.5 | |||||||||
Retail
Electric
retail utility margin was $313.6 million for the year ended December 31, 2009,
and compared to 2008 increased $4.8 million. Increased margin among
the customer classes associated with returns on pollution control equipment and
other investments totaled $4.5 million year over year, and margin associated
with tracked costs such as recovery of MISO and pollution control operating
expenses increased $10.3 million . Management estimates weather,
driven primarily by cooling weather 10 percent milder than the prior year,
decreased residential and commercial margin $5.2 million compared to
2008. Industrial margins, net of the impacts of regulatory
initiatives and recovery of tracked costs, decreased approximately $4.9 million
due primarily to the weak economy. The industrial decreases are due
primarily to lower usage; however, usage began to stabilize during the third and
fourth quarters.
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.
Margin from Wholesale
Electric 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)
|
2009
|
2008
|
2007
|
|||||||||
|
Off-system
sales
|
$ | 6.1 | $ | 23.2 | $ | 16.9 | ||||||
|
Transmission
system sales
|
14.6 | 9.3 | 4.0 | |||||||||
|
Total
wholesale margin
|
$ | 20.7 | $ | 32.5 | $ | 20.9 | ||||||
For the year ended December 31, 2009, wholesale margin was $20.7 million, representing a decrease of $11.8 million, compared to 2008. Of the decrease, $17.1 million relates to lower margin retained by the Company from off-system sales. The Company experienced lower wholesale power marketing margins due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs. During 2008, margin from off-system sales retained by the Company increased $6.3 million, compared to 2007, due to an increase in off peak volumes available for sale off system. This increase in volumes was driven primarily by expiring municipal contracts and increases in wholesale prices. Off-system sales totaled 603.6 GWh in 2009, compared to 1,512.9 GWh in 2008 and 921.3 GWh in 2007. The base rate increase effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August. Results in 2008 and 2009 reflect the impact of that sharing.
Beginning
in June 2008, the Company began earning a return on electric transmission
projects constructed by the Company in its service territory that meet the
criteria of MISO’s regional transmission expansion plans. Margin
associated with these projects and other transmission system operations
increased $5.3 million in 2009 compared to 2008. These returns also
primarily account for the $5.3 million increase in transmission system sales in
2008 compared to 2007.
Purchased
Power
The
Company’s mix of generated and purchased electricity changed during 2009
compared to prior years. For the years ended December 31, 2009, 2008,
and 2007, respectively, the Company purchased approximately 1,159 GWh, 372 GWh,
and 416 GWh of power from the MISO and other sources. The total cost
associated with these volumes of purchased power is approximately $43 million,
$26 million, and $26 million in 2009, 2008, and 2007 respectively, and is
included in the Cost of fuel
& purchased power.
Utility Group Operating
Expenses
Other
Operating
For year
ended December 31, 2009, other
operating expenses were $304.6 million, increasing $4.3 million compared
to 2008. Approximately $10.9 million of the change results from
increased costs directly recovered through utility margin. Examples
of such tracked costs include Ohio uncollectible accounts expense, Indiana gas
pipeline integrity management costs, costs to fund Indiana energy efficiency
programs, and MISO transmission revenues and costs, among
others. Increases in other operating expenses in 2009, not directly
recovered in margin, include an approximate $6.3 million increase for certain
compensation costs and a $4.1 million increase associated with environmental
matters. All other operating expenses were approximately
$17.0 million lower than the prior year driven primarily by
reductions in electric maintenance costs and lower chemical
costs. Despite significantly lower gas costs due to the recession,
Indiana uncollectible accounts expense was only slightly favorable compared to
2008.
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.
Depreciation
& Amortization
In 2009,
depreciation &
amortization expense increased $15.4 million compared to
2008. The increase in depreciation is due largely to plant
additions. Plant additions include the approximate $100 million
SO2
scrubber placed into service January 1, 2009, for which depreciation totaling
$5.6 million is directly recovered in electric utility
margin. Depreciation expense increased $7.1 million in 2008 compared
to 2007. Expense in 2008 includes $3.8 million of increased
amortization associated with prior electric demand side management costs to be
recovered 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
decreased $12.0 million in 2009 compared to 2008 and increased $4.2 million in
2008 compared to 2007. These taxes are primarily revenue-related
taxes. The variations are primarily attributable to volatility in
revenues, inclusive of changes in natural gas prices and gas volumes
sold. These tax expenses are recovered through revenue.
Other
Income-Net
Other income-net reflects
income of $7.8 in 2009, compared to $4.0 million in 2008 and $9.4 million in
2007. The variations are primarily due to volatile market values
associated with investments related to benefit plans.
Interest
Expense
For the
year ended December 31, 2009, interest expense was $79.2
million, which represents a slight decrease of $0.7 million compared to
2008. Lower short-term interest rates and lower average short-term
debt balances have favorably affected interest expense year over year and are
reflective of lower gas prices and the issuance of new long-term
debt. Offsetting the favorable impacts of lower rates and short-term
balances is the impact of two long-term financing transactions completed in
2009. The long-term financing transactions include a second quarter
issuance by Utility Holdings of $100 million in unsecured eleven year notes with
an interest rate of 6.28 percent and a third quarter completion by SIGECO of a
$22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an
interest rate of 5.4 percent.
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.
Income
Taxes
Federal
and state income taxes
decreased $8.4 million in 2009 compared to 2008 and increased $0.9 million in
2008 compared to 2007. The changes are impacted primarily by
fluctuations in pre-tax income and lower effective tax rates. The
lower effective tax rate in 2009 results from more taxable income allocated to
states with low, or no, state income taxes.
Environmental
Matters
Clean Air
Act
The Clean
Air Interstate Rule (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. SIGECO is in
compliance with the current CAIR Phase I annual NOx reduction requirements in
effect on January 1, 2009 and is also in compliance with SO2 reductions
effective January 1, 2010. It is possible that a revised CAIR will
require further reductions in NOx and SO2 from
SIGECO’s generating units. Utilization of the Company’s inventory of
NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of these
allowances were granted to the Company at zero cost, so these changes will not
impact the carrying value.
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. In response to the court decision, USEPA has announced
that it intends to publish proposed Maximum Achievable Control Technology
standards for mercury in 2010. It is uncertain what emission limit
the USEPA is considering, and whether they will address hazardous pollutants in
addition to mercury. It is also possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress.
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. The Company
has invested approximately $100 million in this project. The scrubber
was placed into service on January 1, 2009. Recovery through a rider
mechanism of associated operating expenses including depreciation expense
associated with the scrubber also began on January 1, 2009. The
SO2
scrubber is in 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. While scientific uncertainties exist and the debate
surrounding global climate change is ongoing, current information suggests a
potential for adverse economic and social consequences should world-wide carbon
dioxide (CO2) and other
greenhouse gas emissions continue at present levels.
The
Company emits greenhouse gases (GHG) primarily from its fossil fuel electric
generation plants. The Company uses methodology described in the Acid
Rain Program (under Title IV of the Clean Air Act) to calculate its level of
direct CO2 emissions
from its fossil fuel electric generating plants. The Company’s direct
CO2
emissions from its plants over the past 5 years are represented
below:
|
(in
thousands)
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||
|
Direct
CO2
Emissions (tons)
|
5,500
|
1/
|
8,029
|
7,995
|
7,827
|
8,242
|
|
1/
|
The
decline in emissions from 2008 to 2009 is primarily due to recessionary
impacts that resulted in a 30 percent decrease in
generation. It is not clear to what extent this recent
reduction may continue.
|
Based on
2005 data made available through the Emissions and Generation Resource
Integrated Database (eGRID) maintained by the USEPA, the Company’s direct
CO2
emissions from its fossil fuel electric generation that report under the Acid
Rain Program were less than one half of one percent of all emissions in the
United States from similar sources.
Emissions
from other Company operations, including those from its natural gas distribution
operations, are monitored internally using the Department of Energy 1605(b)
Standard, and the Company is currently assessing how to effectively report these
emissions in relation to the new mandatory reporting regulations set forth by
the USEPA.
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;
|
|
·
|
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;
and
|
|
·
|
The
allocation of zero cost allowances to natural gas distribution companies
if those companies are required to hold allowances for the benefit of the
end use customer.
|
Current
Initiatives to Increase Conservation & Reduce Emissions
The
Company is committed to a policy that reduces greenhouse gas emissions and
conserves energy usage. 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;
|
|
·
|
Building
a renewable energy portfolio 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;
and
|
|
·
|
Developing
renewable energy and energy efficiency performance contracting projects
through its wholly owned subsidiary, Energy Systems
Group.
|
Legislative
Actions & Other Climate Change Initiatives
The U.S.
House of Representatives has passed a comprehensive energy bill that includes a
carbon cap and trade program in which there is a progressive cap on greenhouse
gas emissions and an auctioning and subsequent trading of allowances among those
that emit greenhouse gases, a federal renewable portfolio standard, and utility
energy efficiency targets. Current proposed legislation also requires
local natural gas distribution companies to hold allowances for the benefit of
their customers. As of the date of this filing, the Senate has not
passed a bill, and the House bill is not law.
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 Indiana,
the state is an observer to the Midwestern Regional Greenhouse Gas Reduction
Accord.
In
advance of a federal or state renewable portfolio standard, SIGECO received IURC
approval to purchase a 3 MW landfill gas generation facility from a related
entity. The facility was purchased in 2009 and is directly
interconnected to the Company’s distribution system. In 2009, the
Company also executed a long term purchase power commitment for 50 MW of wind
energy. These transactions supplement a 30 MW wind energy purchase
power agreement executed in 2008. At December 31, 2009, the Company’s
renewable portfolio is approximately 5 percent of total generation
sources.
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 motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. In April of 2009, the USEPA published its proposed
endangerment finding for public comment. The proposed endangerment
finding concludes that carbon emissions from mobile sources pose an endangerment
to public health and the environment. The endangerment finding was
finalized in December of 2009, and is the first step toward USEPA regulating
carbon emissions through the existing Clean Air Act in the absence of specific
carbon legislation from Congress. Therefore, any new regulations
would likely also impact major stationary sources of greenhouse
gases. The USEPA has recently finalized a mandatory greenhouse gas
emissions registry which will require reporting of emissions beginning in 2011
(for the emission year 2010). The USEPA has also recently proposed a
revision to the PSD (Prevention of Significant Deterioration) and Title V
permitting rules which would require facilities that emit 25,000 tons or more of
greenhouse gases a year to obtain a PSD permit for new construction or a
significant modification of an existing facility. If these proposed
rules were adopted, they would apply to SIGECO’s generating
facilities.
Impact
of Legislative Actions & 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 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 with regard operating expenses for the purchase of
allowances, and later for capital expenditures as technology becomes available
to control greenhouse gas emissions. However, these compliance cost
estimates are based on highly uncertain assumptions, including allowance prices
and energy efficiency targets. Costs to purchase allowances that cap
greenhouse gas emissions should be considered a cost of providing electricity
and gas, and as such, the Company believes recovery should be timely reflected
in rates charged to customers. Approximately 20 percent of electric
volumes sold in 2008 were delivered to municipal and other wholesale
customers. As such, reductions in these volumes in 2009 coupled with
the flexibility to further modify the level of these transactions in future
periods may help with compliance since emission targets are expected to be based
on pre-2008 levels.
Ash Ponds & Coal
Ash Disposal Regulations
The USEPA
is considering additional regulatory measures affecting the management and
disposal of coal combustion products, such as ash generated by the Company’s
coal-fired power plants. Additional laws and regulations under
consideration more stringently regulate these byproducts, including the
potential for coal ash to be considered a hazardous waste in certain
circumstances. The USEPA has indicated that it intends to propose a rule
during 2010. At this time, the Company is unable to predict the outcome
any such revised regulations might have on operating results, financial
position, or liquidity.
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. Vectren's own soil testing, completed during the
construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils above industrial cleanup
levels. At this time, it is anticipated that the USEPA may request
only additional soil testing at some future date.
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 $23.2
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 limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50
percent.
With
respect to insurance coverage, Indiana Gas has settled with all known insurance
carriers under insurance policies in effect when these plants were in operation
in an aggregate amount approximating $20.8 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 waste
disposal site subject to potential environmental remediation
efforts. With respect to that lawsuit, in an October 2009 court
decision, SIGECO was found to be a PRP at the site. However, the
Court must still determine whether such costs should be allocated among a number
of PRPs, including the former owners of the site. 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.
SIGECO
has recorded cumulative costs that it reasonably expects to incur related to
these environmental matters totaling approximately $11.1
million. However, given the uncertainty surrounding the allocation of
PRP responsibility associated with the May 2007 lawsuit and other matters, the
total costs that may be incurred in connection with addressing all of these
sites cannot be determined at this time. With respect to insurance
coverage, SIGECO has settled with certain of its known insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.1 million; negotiations are ongoing with others.
Total
costs expected to be incurred 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, 2009 and December 31, 2008, approximately $6.5 million of accrued,
but not yet spent, remediation costs are included in Other Liabilities related to
both the Indiana Gas and SIGECO sites.
Rate
& 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 PUCO has
completed all audits of periods prior to October 2008, and no issues or findings
are outstanding. After October 1, 2008, the Company is no longer the
supplier, and the GCR is no longer necessary.
Vectren South Electric Base
Rate Filing
On
December 11, 2009, the Company filed a request with the IURC to adjust its
electric base rates in its South service territory. The requested
increase in base rates addresses capital investments, a modified electric rate
design that facilitates a partnership between the Company and customers to
pursue energy efficiency and conservation, and new energy efficiency programs to
complement those currently offered for natural gas customers. In
total the request approximated $54 million. The request addresses the
roughly $325 million spent in infrastructure construction since its last base
rate increase in August 2007 that was needed to continue to provide reliable
service. Most of the remainder of the request is to account for the
now lower overall sales levels resulting from the recession. A
portion of the request reflects a slight increase in annual operating and
maintenance costs since the last rate case, nearly four years
ago. The rate design proposed in the filing would break the link
between customers’ consumption and the utility’s rate of return, thereby
aligning the utility’s and customers’ interests in using less
energy. The request assumes an overall rate of return of 7.62 percent
on rate base of approximately $1,294 million and an allowed return on equity
(ROE) of 10.7 percent. Based upon timelines prescribed by the IURC at
the start of these proceedings, a decision is expected to be issued at the end
of 2010.
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 adjusted the rate design used to collect the agreed-upon revenue from
VEDO's customers. The order allows for the phased movement toward a
straight fixed variable rate design which places substantially all of the fixed
cost recovery in the customer service charge. A straight fixed
variable design mitigates most 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 on February 22, 2009. In
2008, annual results include approximately $4.3 million of revenue from a lost
margin recovery mechanism that did not continue once this base rate increase
went into effect. After year one, nearly 90 percent of the combined
residential and commercial base rate margins were recovered through the customer
service charge. 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. The Ohio Supreme Court has yet to act on the OCC’s request
in this instance, but in two similar cases, the Court denied such
requests.
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 uncollectible accounts
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. The straight fixed variable rate
design will be fully phased in by February 2010.
VEDO Continues the 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 eliminated the need
for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits.
In October 2008, VEDO’s entire natural gas inventory was transferred, receiving
proceeds of approximately $107 million.
The
second phase of the exit process begins on April 1, 2010, during which the
Company will no longer sell natural gas directly to these
customers. Rather, state-certified Competitive Retail Natural Gas
Suppliers, that are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers for 12 months at
auction-determined standard pricing. That auction was conducted on
January 12, 2010, and the auction results were approved by the PUCO on January
13. The plan approved by the PUCO requires that the Company conduct at
least two auctions during this phase. As such, the Company will conduct
another auction in advance of the second 12-month term, which will commence on
April 1, 2011. Consistent with current practice, customers will
continue to receive one bill for the delivery of natural gas
service.
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 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 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 uncollectible accounts expense level based on
historical experience and unaccounted for gas through the existing GCA
mechanism, and tracking of pipeline integrity management
expense.
-35-
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 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 uncollectible accounts 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 Electric Base
Rate Order Received
In August
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.
MISO
Since
2002 and with the IURC’s approval, the Company has been a member of the 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.
Historically,
the Company has typically been in a net sales position with MISO as generation
capacity is in excess of that needed to serve native load and is from time to
time 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 & 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. The Company also has municipal
customers served through the MISO and for which the Company transmits power to
the MISO for delivery to those customers. Net revenues from wholesale
activities, inclusive of revenues associated with these municipal contracts,
totaled $20.8 million in 2009, $57.6 million in 2008, and $35.0 million in
2007. The base rate case effective August 17, 2007, requires that
wholesale margin (net revenues less the cost of fuel & purchased power)
inclusive of this MISO wholesale activity earned above or below $10.5 million be
shared equally with retail customers as measured on a fiscal year ending in
August.
Recently,
MISO market prices have fallen and the Company has more frequently been a net
purchaser. In addition, the Company also receives power through the
MISO associated with its wind and other power purchase
agreements. Including these power purchase agreements, the Company
purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in
2008, and $18.2 million in 2007. To the extent these power purchases
are used for retail load, they are subject to FAC filings.
-36-
The
Company also receives transmission revenue that results from other MISO 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 from / refunded to retail
customers 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 recover costs associated with ASM. To
date impacts from the ASM have been minor.
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. Beginning in
June 2008, the Company began timely recovering its investment in certain new
electric transmission projects that benefit the MISO regional infrastructure at
a FERC approved rate of return. Such revenues recorded in Electric utility revenues
associated with projects meeting the criteria of MISO’s transmission
expansion plans totaled $9.1 million in 2009 and $4.8 million in
2008.
One such
project currently under construction is an interstate 345 kilovolt
transmission line that will connect Vectren’s A.B. Brown Generating 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 updated annually for estimated costs to be incurred. Of the total
investment, which is expected to approximate $75 million, as of December 31,
2009, the Company has invested approximately $21.3 million. The
Company expects this project to be fully 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,
2009, 2008, and 2007, follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share amounts)
|
2009
|
2008
|
2007
|
|||||||||
|
NET
INCOME EXCLUDING LIBERTY CHARGE
|
$ | 37.7 | $ | 18.9 | $ | 37.0 | ||||||
|
CONTRIBUTION
TO VECTREN BASIC EPS,
EXCLUDING
LIBERTY CHARGE
|
$ | 0.47 | $ | 0.24 | $ | 0.49 | ||||||
|
NET
INCOME ATTRIBUTED TO:
|
||||||||||||
|
Energy Marketing & Services (Excluding Liberty Charge)
|
$ | 16.0 | $ | 18.0 | $ | 22.3 | ||||||
|
Mining
Operations
|
13.4 | (4.6 | ) | 2.0 | ||||||||
|
Energy
Infrastructure Services
|
10.8 | 11.4 | 9.4 | |||||||||
|
Other
Businesses
|
(2.5 | ) | (5.9 | ) | 0.3 | |||||||
|
Synfuels-related
|
- | - | 3.0 | |||||||||
Including
the Liberty Charge of $11.9 million after tax, the Nonutility Group generated
net income of $25.8 million for the year ended December 31,
2009.
Impact
of the Recent Recession
Despite
the beginning of recovery, the recent recession has resulted in, and may
continue to result in, a lower level of economic activity and greater
uncertainty regarding energy prices and other key factors that impact the
Nonutility Group. Economic declines have been accompanied by a
decrease in demand for products and services offered by nonutility
operations. The recent recession has had, and may continue to 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 if a weak economy continues,
there could be 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. Operating entities contributing to these results include
ProLiance and Vectren Source. Results, inclusive of holding company
costs but excluding the Liberty Charge of $11.9 million after tax, from Energy
Marketing and Services for the year ended December 31, 2009, were earnings of
$16.0 million, compared to $18.0 million
in 2008 and $22.3 million in 2007.
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. For the year
ended December 31, 2009, 2008, and 2007, the amounts recorded to Equity in earnings of unconsolidated
affiliates related to ProLiance’s operations, excluding the Liberty
Charge, totaled income of $23.6 million, $39.5 million, and $41.0 million,
respectively.
Vectren
Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the
Company’s investment in ProLiance. Within the consolidated entity,
EMS is responsible for certain financing costs associated with ProLiance and is
also responsible for income taxes related to the Company’s portion of
ProLiance’s results. During the year ended December 31, 2009,
ProLiance’s earnings, inclusive of financing costs and income taxes, were
approximately $9.6 million compared to $19.3 million in 2008 and $22.9 million
in 2007.
During
2009, ProLiance’s earnings contribution decreased $9.7 million compared to
2008. The decrease primarily reflects lower cash to NYMEX spreads
compared to the prior year, particularly spreads existing in the third quarter
of 2008 that had unprecedented price volatility and resulted in record quarterly
earnings from ProLiance. ProLiance’s earnings contribution decreased
$3.6 million in 2008 compared to 2007 and is reflective of lower operating
results. ProLiance’s storage capacity at December 31, 2009 is 46 Bcf
compared to 42 Bcf at December 31, 2008 and 40 Bcf at December 31,
2007.
Investment
in Liberty Gas Storage
Liberty
Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance
and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern
natural gas storage facilities. ProLiance is the minority member with a 25
percent interest, which it accounts for using the equity method. The
project was expected to include 17 Bcf of capacity in its north facility
(previously referred to as the Sulfur site, located near Sulfur, Louisiana), and
an additional 17 Bcf of capacity in its south facility (previously referred to
as the Hackberry site, near Hackberry, Louisiana). As more fully
described below, it is now expected that only the south facility will be
completed by the joint venture. This facility is expected to provide
at least 17 Bcf of capacity. The Liberty pipeline system is currently connected
with several interstate pipelines, including the Cameron Interstate Pipeline
operated by Sempra Pipelines & Storage, and will connect area LNG
regasification terminals to an interstate natural gas transmission system and
storage facilities. ProLiance’s investment in Liberty is $37.3
million at December 31, 2009, after reflecting the charge discussed
below.
In late
2008, SE advised ProLiance that the completion of the phase of Liberty’s
development at the north site had been delayed by subsurface and well-completion
problems. Based on testing performed in the second quarter of 2009,
SE determined that attempts at corrective measures had been unsuccessful in
development of certain caverns. At June 30, 2009, Liberty recorded a
charge of approximately $132 million to write off the north caverns and certain
related assets. As an equity investor in Liberty, ProLiance recorded
its share of the charge, totaling $33 million at June 30, 2009. The
Company’s share is $11.9 million after tax, or $0.15 per share. In
the Consolidated Statement of
Income for the year ended December 31, 2009, the charge is an approximate
$19.9 million reduction to Equity in earnings of unconsolidated
affiliates and an income tax benefit reflected in Income taxes of approximately
$8.0 million. The Company and ProLiance do not expect issues
associated with Liberty to impact future liquidity or access to
capital. Further, it is not expected that the delay in Liberty’s
development will impact ProLiance’s ability to meet the needs of its
customers.
Regulatory
Matter Resolved
ProLiance
self reported to the 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. During the second quarter of 2009, ProLiance resolved the
matter with FERC. The amount of the penalty was not material to the
Company’s consolidated operating results, financial position or cash
flows.
Vectren
Source
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 $6.4 million in 2009,
compared to $1.9 million in 2008 and $1.2 million in 2007. The record
earnings in 2009 resulted primarily from favorable market conditions over the
course of 2009’s first quarter as revenues on variable priced sales contracts
fell more slowly than gas costs. Results in 2008 were impacted by a
$0.5 million gain on the sale of its Georgia customer base. Vectren
Source’s customer count at December 31, 2009 was approximately 189,000
equivalent customers, compared to 170,000 at December 31, 2008 and 161,000 at
December 31, 2007. This customer base reflects nearly 33,000
equivalent customers in VEDO’s service territory as part of VEDO’s process of
exiting the merchant function. Vectren Source began providing
services to these VEDO customers on October 1, 2008. This service will end March
31, 2010. Vectren Source was a successful bidder in the second
regulatory-approved auction that was conducted on January 12, 2010 related to
VEDO’s exit the merchant function. As a result of this auction, Vectren
Source will sell gas commodity directly to approximately 35,000 equivalent
customers in VEDO’s service territory through April 1, 2011.
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. (Vectren
Fuels). Coal Mining, inclusive of holding company costs, earned
approximately $13.4 million in 2009, compared to a loss of $4.6 million in 2008
and earnings of $2.0 million in 2007.
Compared
to 2008, Coal Mining earnings have increased based on new contract pricing
effective January 1, 2009. The impact of higher revenues has been somewhat
offset by increased costs per ton mined and the recession. The
anticipated cost increase was reflective of efforts to reconfigure the mining
operation at Prosperity mine in order to improve future productivity and meet
Mine Safety and Health Administration (MSHA) requirements. During the
second half of 2009, these improvements began to favorably impact production and
operating costs. The recent recession resulted in a decrease in the demand
for, and market price of, Illinois Basin coal and lower than anticipated
earnings from coal mining operations. The lowered demand has caused
some build up of coal inventory at most customer locations as well as at Vectren
Fuels’ mines. As a result of contracts with minimum delivery
provisions, certain customers scaled back their deliveries within specified
limits. This resulted in less 2009 mine production as Vectren Fuels
reduced production to align with customer’s needs. Further, Vectren
Fuels is currently in a dispute with one customer regarding its purchase
contract, and Vectren Fuels is working to resolve the dispute. In the
current market conditions, Vectren Fuels sold 3.5 million tons in 2009 compared
to 4.2 million tons in 2008 and 4.7 million tons in 2007. The
original expectation for 2009 was to sell between 4.6 and 5.2 million
tons. Further, the higher customer coal inventory levels will likely
cause the current demand and supply imbalance to extend into
2010. Early 2010 has shown some decline in customer inventory levels,
due largely to colder weather and the resulting increased demand.
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 MSHA
regulatory guidelines which necessitated changes to the mining
plan. As a result, the yield at the Prosperity mine decreased
approximately 4 percent in 2008 compared to 2007. In addition, 2008
was impacted by higher diesel fuel costs and unfavorable geologic conditions at
the Company’s surface mine, which resulted in more costs to enhance the BTU
content of mined coal.
Oaktown
Mines
The first
of two new underground mines located near Vincennes, Indiana, which began minor
coal extraction in the latter half of 2009, is now operational. The second
mine is currently expected to open in 2011. However, Vectren Fuels may
continue to change this time table as it evaluates the impacts of current market
conditions. Reserves at the two mines are estimated at about 100 million
tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur
dioxide. The reserves at these new mines bring total coal reserves to
approximately 135 million tons at December 31, 2009. Once in production,
the two new mines are capable of producing about 5 million tons of coal per
year. Due to the delay in the opening of the mines, management expects to
incur approximately $200 million to access the coal reserves. At December
31, 2009, Vectren Fuels has invested approximately $174 million in the new
mines.
Energy
Infrastructure Services
Energy
Infrastructure Services provides energy performance contracting and renewable
energy services through Energy Systems Group, LLC (ESG) and underground
construction and repair to utility infrastructure through Miller Pipeline
Corporation (Miller). Inclusive of holding company costs, Energy
Infrastructure’s operations contributed earnings of $10.8 million in 2009,
compared to $11.4 million in 2008 and $9.4 million in 2007.
Energy Systems
Group
ESG’s
earnings were $8.8 million in 2009, compared to $6.7 million in 2008 and $4.0
million in 2007. The increases are primarily due to the continued
focus on renewable energy, energy conservation, and sustainability measures by
ESG’s customers. In 2009, the increase is primarily a result of
increased performance contracting revenues. As part of ESG’s ongoing
renewable energy project development strategy, results in 2009 include the sale
of a 3 MW self-developed landfill gas facility. With approval from
the IURC, the facility was sold to SIGECO, as part of the utility’s strategy to
continue to build a renewable energy portfolio. ESG’s results
associated with this renewable project match the results of a similar land fill
gas project completed near Atlanta, Georgia in 2008. At December 31,
2009, ESG’s backlog was $70 million, compared to $65 million at December 31,
2008 and $52 million at December 31, 2007. The national focus on a
comprehensive energy strategy as evidenced by the Energy Independence and
Security Act of 2007 and the American Recovery and Reinvestment Act of 2009 is
likely to create favorable conditions for ESG’s growth and resulting
earnings.
Miller
Pipeline
Miller’s
2009 earnings were $3.1 million compared to $6.2 million in 2008 and $6.1
million in 2007. The decrease in 2009 primarily results from customer
cutbacks in spending as a result of the recession. In addition,
startup costs associated with new contracts also negatively impacted year over
year results. Lower interest rates partially offset the lower
margins. The years ended December 31, 2008 and 2007 were record years
in terms of earnings contribution from Miller. As the country
continues to replace its aging natural gas infrastructure and needs for shale
gas infrastructure become more prevalent, Miller is positioned for future
growth.
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).
As of
December 31, 2009, remaining legacy investments included in the Other Businesses
portfolio total $64.5 million, of which $46.2 million are included in Other nonutility investments
and $18.3 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 $9.7
million; affordable housing projects $7.8 million; leveraged leases $17.5
million, and other investments, including a note receivable from the City of
Alameda, California, $8.5 million. As of December 31, 2008,
investments totaled $71.8 million.
Other
Businesses reported a loss of $2.5 million in 2009, compared to a loss of $5.9
million in 2008 and earnings of $0.3 million in 2007. Results in 2008
reflect a write-down associated with commercial real estate
investments.
2008 Commercial Real Estate
Charge
The
recent economic recession impacted the value of commercial real estate
investments within this portfolio, and the prospect for recovery of that value
diminished. During 2008, the Company assessed its commercial real
estate investments for impairment and identified the need to reduce their
carrying values. The 2008 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. The charge impacted the carrying values of
primarily notes receivable collateralized by commercial real estate and an
office building of which the Company took possession when a leveraged lease
expired in 2008 and that is currently for sale.
Synfuel-Related
Activity
Tax laws
authorizing synfuel credits expired on December 31, 2007. Prior to
that date, the Company had active synthetic fuel investments, including an
investment in Pace Carbon Synfuels, LP (Pace Carbon). In addition,
Vectren Fuels generated processing fees from other synfuel
producers. Activity since December 31, 2007 has been insignificant
and is generally focused on winding down partnership operations at Pace
Carbon.
Generally, the statute of limitations
for the IRS to audit a tax return is three years from filing. Therefore,
tax credits generated by the investment in Pace Carbon and utilized in 2006 –
2007 are still subject to IRS examination. However, avenues remain where
the IRS could challenge tax credits for the years prior to 2006. As a
partner of Pace Carbon, Vectren reflected cumulative synfuel tax credits of
approximately $101 million in its consolidated results, of which approximately
$22 million were generated in 2006 and 2007. Vectren has utilized 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 IRC, as adjusted for inflation. Due to 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. The Company executed several financial contracts to hedge
oil price risk. Income statement activity associated with these
contracts was a gain of $13.4 million in 2007. This activity is
reflected in Other-net
along with the effects of impairing the Pace Carbon investment in 2006 in
advance of equity method losses experienced in 2007.
The
investment in Pace Carbon resulted in losses reflected in Equity in earnings of unconsolidated
affiliates totaling $20.0 million in 2007. 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. Of those earnings, which did 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.
Use of Non-GAAP Performance
Measures
Contribution
to Vectren’s basic EPS
|
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 in analyzing consolidated period to
period changes. Reconciliations of these non-GAAP measures to
their most closely related GAAP measure of consolidated earnings per share
are included throughout this discussion and
analysis.
|
Results
Excluding the Liberty Charge
This
discussion and analysis contains other non-GAAP financial measures that exclude
the charge related to ProLiance’s investment in Liberty Gas Storage, LLC
(Liberty Charge) recorded during 2009.
Management
uses consolidated net income, consolidated earnings per share, and Nonutility
Group net income, excluding the Liberty Charge, to evaluate its
results. Management believes analyzing underlying business trends is
aided by the removal of the Liberty Charge due to the significant impact it has
on comparability between the periods reported. The rationale for
using such non-GAAP measures is that the charge in all cases substantially
decreases the performance measures, and the period to period changes do not
provide meaningful comparative information regarding typical operating
results.
A
material limitation associated with the use of these measures excluding the
Liberty Charge is that these measures excluding the Liberty Charge do not
include all costs (i.e. the Liberty Charge) recognized in accordance with
GAAP. Management compensates for this limitation by prominently
displaying a reconciliation of these non-GAAP performance measures to their
closest GAAP performance measures. This display also provides
financial statement users the option of analyzing results as management does or
by analyzing GAAP results.
The following table reconciles consolidated net income, consolidated basic EPS, and Nonutility Group net income to those results excluding the Liberty Charge.
|
Year
Ended December 31, 2009
|
||||||||||||
|
(In
Millions, except EPS)
|
GAAP-
Measure
|
Exclude
Liberty Charge
|
Non-GAAP
Measure
|
|||||||||
|
Consolidated
|
||||||||||||
|
Net
Income
|
$ | 133.1 | 11.9 | $ | 145.0 | |||||||
|
Basic
EPS
|
$ | 1.65 | 0.15 | $ | 1.80 | |||||||
|
Nonutility
Group Net Income
|
$ | 25.8 | 11.9 | $ | 37.7 | |||||||
The non-GAAP financial measures disclosed by the Company should not be considered a substitute for, or superior to, financial measures calculated in accordance with GAAP, and the financial results calculated in accordance with GAAP.
Impact of Recently Issued
Accounting Guidance
Business
Combinations
On
January 1, 2009, the Company adopted new FASB guidance related to business
combinations. This guidance 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. The guidance applies to all transactions or
other events in which one entity acquires control of one or more businesses and
applies to all business entities. To date, the adoption of this
standard has not had a material impact.
Noncontrolling
Interests in Consolidated Financial Statements
On
January 1, 2009, the Company adopted new FASB guidance related to noncontrolling
interests in consolidated financial statements. This guidance
establishes accounting and reporting standards that require ownership
percentages in material 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. The adoption of this guidance on January 1,
2009 had an immaterial impact to the Company’s presentation of its financial
position and operating results.
Subsequent
Events
The
Company adopted new FASB guidance related to management’s review of subsequent
events on June 30, 2009. In the instance of a public registrant such
as the Company, this guidance establishes the accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are “issued”, as that term is defined in the guidance. Such
disclosure is included in Note 2 to these consolidated financial
statements.
Accounting
Standards Codification
The
Company adopted FASB guidance related to the FASB Accounting Standards
Codification (ASC) and the Hierarchy of GAAP. This statement
identifies the sources of accounting principles and the framework for selecting
the principles used in the preparation of financial statements of
nongovernmental entities that are presented in conformity with GAAP in the
United States. This statement replaces prior guidance related to the
hierarchy of GAAP and establishes the FASB ASC as the source of authoritative
accounting principles recognized by the FASB. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources
of authoritative GAAP for all SEC registrants. The adoption of this
guidance did not have any impact on amounts recorded on the financial
statements.
Accounting
for Liabilities Measured at Fair Value with a Third-Party Credit
Enhancement
On
January 1, 2009, the Company adopted FASB guidance related to issuer’s
accounting for liabilities measured at fair value with a third-party credit
enhancement. This guidance states that companies should not include
the effect of third-party credit enhancements in the fair value measurement of
the related liabilities. The guidance also requires companies with
outstanding liabilities measured or disclosed at fair value to disclose the
existence of credit enhancements, to disclose valuation techniques used to
measure liabilities and to include a discussion of changes, if any, from the
valuation techniques used to measure liabilities in prior periods.
As of
December 31, 2009, the Company has approximately $250.0 million of debt
instruments that are supported by a third party credit enhancement feature such
as insurance from a monoline insurer or a letter of credit posted by third party
that supports the Company’s credit facilities. The Company’s
valuation techniques did not materially change as a result of the adoption of
this guidance.
Determination
of the Useful Life of Intangible Assets
In April
2008, the FASB issued guidance related to the determination of the useful life
of intangible assets. This guidance amends the factors that should be considered
in developing renewal or extension assumptions used to determine the useful life
of a recognized intangible asset under other guidance related to goodwill and
other intangible assets. On January 1, 2009, the Company adopted this
guidance and such adoption did not have a material impact on the consolidated
financial statements.
Employers’
Disclosures about Postretirement Benefit Plan Assets
In
December 2009, the Company adopted new accounting guidance for employers’
disclosures about postretirement benefit plan assets. This guidance
amends the plan asset disclosures required under prior guidance by the FASB to
provide guidance on an employer’s disclosures about plan assets of a defined
benefit pension or other postretirement plan. The guidance relates to
disclosures about investment policies and strategies, categories of plan assets,
fair value measurements of plan assets, and significant concentrations of
risk. Such disclosure is included in Note 9 to the financial
statements.
Variable
Interest Entities
In June
2009, the FASB issued new accounting guidance regarding variable interest
entities (VIE’s). This new guidance is effective for annual reporting
periods beginning after November 15, 2009. This guidance requires a
qualitative analysis of which holder of a variable interest controls the VIE and
if that interest holder must consolidate a VIE. Additionally, it
requires additional disclosures and an ongoing reassessment of who must
consolidate a VIE. The Company adopted this guidance on January 1,
2010. The Company does not expect the adoption will have a material impact on
the consolidated financial statements.
Fair
Value Measurements & Disclosures
In
January 2010, the FASB issued new accounting guidance on improving disclosures
about fair market value. This guidance amends prior disclosure
requirements involving fair value measurements to add new requirements for
disclosures about transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances, and settlements relating to Level
3 measurements. The guidance also clarifies existing fair value disclosures in
regard to the level of disaggregation and about inputs and valuation techniques
used to measure fair value. The guidance also amends prior disclosure
requirements regarding postretirement benefit plan assets to require that
disclosures be provided by classes of assets instead of major categories of
assets. This guidance is effective for the first reporting period
beginning after December 15, 2009. The Company will adopt this
guidance in its first quarter 2010 reporting. The Company does not
expect the adoption will have a material impact on the consolidated financial
statements.
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 in certain cases for notes that are collateral dependent, a
comparison of the collateral’s fair value, to the carrying amount of the
note. An impairment analysis of equity investments involves
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 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), among others.
The
recent economic recession impacted the value of commercial real estate
investments within the Other Businesses nonutility portfolio, and the prospect
for recovery of that value has diminished. During 2008, the Company
assessed its commercial real estate investments for impairment using the methods
described above and identified the need to reduce their carrying
values. The impairment charge recorded in 2008 totaled $10.0
million.
Significant
assumptions impacting these analyses were holding periods, net operating income
and capitalization rates, which have increased in the recent economic and credit
constrained environment. Related to capitalization rates, the Company
used a 9.75 cap rate in its valuation of a suburban Chicago commercial real
estate holding owned by the Company that is currently vacant and a 9.25 cap rate
in its valuation of 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. The Company examined these investments for
impairment throughout 2009, noting that current capitalization rates and other
assumptions indicate no further impairment at December 31,
2009. Actual realized values, however, could differ from these
estimates.
Goodwill
& 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 19 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 and other market based information 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 has been in excess of the carrying amount in each of the last three
years 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 the last three years, these tests yielded no impairment
charges.
Pension &
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
obtains actuarial estimates to assess the future potential liability and funding
requirements of the Company's pension and postretirement plans. The
Company used the following weighted average assumptions to develop 2009 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. These key assumptions
were unchanged from the assumptions utilized in 2008. To estimate
2010 costs, the discount rate, expected return on plan assets, rate of
compensation increase, and inflation assumption were 6.0 percent, 8.0 percent,
3.5 percent, and 3.0 percent respectively. Management currently
estimates a pension and postretirement cost of approximately $13 million in
2010, compared to approximately $15 million in 2009, $11 million in 2008, and
$14 million in 2007. 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
2010 projected costs would generally increase periodic benefit cost by
approximately $1.6 million. A 50 basis point decrease in the discount
rate used to estimate 2009 periodic cost would have increased costs 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 FASB
guidance related to accounting for the effects of certain types of
regulation. 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, 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 primarily 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, 2009 approximated $332 million and $197 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, 2009 approximated $920 million and $16
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. SIGECO will also occasionally issue tax exempt debt to
fund qualifying pollution control capital expenditures.
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, 2009, 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/A2. 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. During the third quarter of 2009, Moody’s raised its
credit rating on SIGECO’s secured debt from A3 to A2; otherwise, these ratings
and outlooks did not change during 2009. 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
46 percent and 50 percent of long-term capitalization at December 31, 2009 and
2008, respectively. 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, 2009, the Company was in compliance with all financial
covenants.
Available
Liquidity in Current Credit Conditions
The
Company’s A-/Baa1 investment grade credit ratings have allowed it to access the
capital markets as needed during this period of financial market
volatility. Over the last twelve to twenty four months, the Company
has significantly enhanced its short-term borrowing capacity with the completion
of several long-term financing transactions including the issuance of long-term
debt in both 2008 and 2009 and the settlement of an equity forward contract in
2008. The liquidity provided by these transactions, when coupled with
existing cash and expected internally generated funds, is expected to be
sufficient over the near term to fund anticipated capital expenditures,
investments, debt security redemptions, and other working capital
requirements.
Debt
redemptions total $48 million in 2010. In 2011, $250 million is
due. The Company is currently considering the level
of need for Nonutility Group long-term debt and whether to prefund a
portion of the $250 million Utility Group debt redemption with a long-term debt
issuance in 2010. In addition, investors have the one-time option to
put $10 million in May of 2010 and a one time option to put $30 million in
2011.
Long-term
debt transactions completed in 2009 include a $150 million issuance by Vectren
Capital and a $100 million issuance by Vectren Utility
Holdings. SIGECO also recently remarketed $41.3 million of long-term
debt, supported by letters of credit issued under Vectren Utility Holdings'
credit facility and completed a $22.3 million tax-exempt first mortgage bond
issuance. These transactions, along with financing transactions
completed in 2008 and 2007, are more fully described below.
Consolidated Short-Term
Borrowing Arrangements
At
December 31, 2009, the Company had $775 million of short-term borrowing
capacity, including $520 million for the Utility Group and $255 million for the
wholly owned Nonutility Group and corporate operations. As reduced by
letters of credit and borrowings currently outstanding, approximately $462
million was available for the Utility Group operations and approximately $48
million was available for the wholly owned Nonutility Group and corporate
operations. Of the $520 million in Utility Group capacity, $5 million
is available through June, 2010 and $515 million is available through November,
2010; and the $255 million in Nonutility Group capacity is available through
November, 2010. In September of 2009, approximately $120 million of
short-term credit capacity specific to the Nonutility Group was no longer needed
as a result of the recent long-term debt issuance by Vectren Capital and was not
renewed. In addition, a $10 million credit facility at Energy
Systems Group, one of the Company's wholly-owned nonutility
subsidiaries, also expired during 2009. This supplemental
facility was no longer needed and thus was not renewed.
Historically,
the Company uses short-term borrowings to supplement working capital needs and
also to fund capital investments and debt redemptions until financed on a
long-term basis. The Company has historically 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 turmoil and volatility in the
financial markets. As a result, the Company met short-term financing needs
through a combination of A2/P2 commercial paper issuances and draws on
Utility Holdings’ $515 million commercial paper back-up credit facilities.
Throughout 2009, the Company has been able to place commercial paper without any
significant issues. However, the level of required short-term
borrowings is significantly lower compared to historical trends due to the
recently completed long-term financing transactions.
Compared
to historical trends, the Company anticipates over the next several years a
greater use of the long-term capital markets to more timely finance capital
investments and other growth as well as debt security
redemptions. This change comes as short-term borrowing arrangements
have become less certain, more volatile, and the cost of unutilized capacity is
expected to increase significantly. Thus, while the Company expects
to renew these facilities in 2010, the Company anticipates that borrowing levels
will be lower due to the reduced requirements for short-term borrowings
described above. Under current market conditions, this change is
expected to yield greater certainty to financing business operations at the
expense of some increase in interest costs.
ProLiance Short-Term
Borrowing Arrangements
ProLiance,
a nonutility energy marketing affiliate of the Company, has separate borrowing
capacity available through a syndicated credit facility. ProLiance
renegotiated a new credit facility with terms to expire June 14,
2010. The terms of this facility allow for $315 million of capacity,
as adjusted for letters of credit and current inventory and receivable balances.
This credit facility, when coupled with internally generated funds, is expected
to provide sufficient liquidity to meet ProLiance's operational
needs. As of December 31, 2009, no borrowings were
outstanding. 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 $5.8
million in 2009, $1.2 million in 2008 and $5.2 million in 2007. In
2010, new issuances required to meet these various plan requirements are
estimated to be consistent with issuances in 2009.
Potential
Uses of Liquidity
Pension
& Postretirement Funding Obligations
As of
December 31, 2009, asset values of the Company’s qualified pension plans were
approximately 82 percent of the projected benefit obligation. In
order to increase the funded status, management currently estimates the
qualified pension plans require Company contributions of $12 million in
2010. Under current market conditions, the Company estimates similar
funding in 2011. During 2009, approximately $34 million in
contributions to qualified pension plans were made. In addition to
the qualified plan funding, the Company anticipates payments totaling $20
million in 2010 associated with its other retirement and deferred compensation
plans.
Corporate
Guarantees
The
Company issues corporate guarantees to certain vendors and customers of its
wholly owned subsidiaries and unconsolidated affiliates. These
guarantees do not represent incremental consolidated obligations; rather, they
represent parental guarantees of subsidiary and unconsolidated affiliate
obligations in order to allow those subsidiaries and affiliates the flexibility
to conduct business without posting other forms of collateral. At
December 31, 2009, corporate issued guarantees support a portion of ESG’s
performance contracting commitments and warranty obligations described
below. In addition, the Company has approximately $60 million of
other guarantees outstanding supporting other consolidated subsidiary
operations, of which $46 million support non-regulated retail gas supply
operations. Guarantees issued and outstanding on behalf of
unconsolidated affiliates approximated $3 million at December 31, 2009. These
guarantees relate primarily to arrangements between ProLiance and various
natural gas pipeline operators. The Company has not been called upon to
satisfy any obligations pursuant to these parental guarantees and has accrued no
significant liabilities related to these guarantees.
Performance
Guarantees & Product Warranties
In the
normal course of business, ESG and other wholly owned subsidiaries issue
performance bonds or other forms of assurance that commit them to timely install
infrastructure, operate facilities, pay vendors or subcontractors, and/or
support warranty obligations. Based on a history of meeting
performance obligations and installed products operating effectively, no
significant liability or cost has been recognized during the periods
presented.
Specific
to ESG, in its role as a general contractor in the performance contracting
industry, at December 31, 2009, there are 54 open surety bonds supporting future
performance. The average face amount of these bonds is $3.6 million, and the
largest obligation has a face amount of $30.4 million. These surety
bonds are guaranteed by Vectren Corporation. The maximum exposure of
these obligations is less than these amounts for several factors, including the
level of work already completed. At December 31, 2009, over 50
percent of work was completed on projects with open surety bonds. A
significant portion of these commitments will be fulfilled within one
year. In instances where ESG operates facilities, project guarantees
extend over a longer period.
In
addition to its performance obligations, ESG also warrants the functionality of
certain installed infrastructure generally for one year and the associated
energy savings over a specified number of years. In certain
instances, these warranty obligations are also backed by Vectren
Corporation.
Planned Capital Expenditures
& Investments
Planned
utility and nonutility capital expenditures and investments, including
contractual purchase and investment commitments discussed below, for the
five-year period 2010 - 2014 are estimated as follows:
|
(In
millions)
|
2010
|
2011
|
2012
|
2013
|
2014
|
|||||||||||||||||||
|
Utility
Group
|
$ | 245 | $ | 230 | $ | 210 | $ | 195 | $ | 215 | ||||||||||||||
|
Nonutility
Group
|
120 | 80 | 75 | 70 | 70 | |||||||||||||||||||
|
Total
capital expenditures & investments
|
$ | 365 | $ | 310 | $ | 285 | $ | 265 | $ | 285 | ||||||||||||||
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2009:
|
(In
millions)
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
|||||||||||||||||||||
|
Long-term
debt (1)
|
$ | 1,639.8 | $ | 48.0 | $ | 250.0 | $ | 60.0 | $ | 105.0 | $ | 30.0 | $ | 1,146.8 | ||||||||||||||
|
Short-term
debt
|
213.5 | 213.5 | - | - | - | - | - | |||||||||||||||||||||
|
Long-term
debt interest commitments
|
1,179.3 | 98.8 | 94.5 | 77.5 | 73.0 | 68.1 | 767.4 | |||||||||||||||||||||
|
Nonutility
commodity purchase commitments
|
33.9 | 4.9 | 3.8 | 8.2 | 8.4 | 8.6 | - | |||||||||||||||||||||
|
Operating
leases
|
10.3 | 4.5 | 2.6 | 1.4 | 0.8 | 0.7 | 0.3 | |||||||||||||||||||||
|
Total
(2)
|
$ | 3,076.8 | $ | 369.7 | $ | 350.9 | $ | 147.1 | $ | 187.2 | $ | 107.4 | $ | 1,914.5 | ||||||||||||||
|
(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 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012
and thereafter.
|
|
(2)
|
The
Company has other long-term liabilities that total approximately $205
million. This amount is comprised of the
following: pension obligations $55 million, postretirement
obligations $71 million, deferred compensation and share-based
compensation obligations $24 million, asset retirement obligations $33
million, investment tax credits $6 million, environmental remediation
obligations $6 million, and other obligations including unrecognized tax
benefits totaling $10 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, electricity, and coal 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, 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 $449.6 million in 2009,
compared to $423.2 million in 2008 and $298.1 million in 2007.
In 2009,
operating cash flows increased $26.4 million compared to 2008 due to increased
cash generated from consolidated companies. This is evident from a
$51.7 million year over year increase in net income before the impacts of
depreciation, deferred taxes, equity in earnings of unconsolidated affiliates
and other non-cash charges. Tax payments in both 2009 and 2008 were
favorably impacted by federal stimulus plans authorizing bonus depreciation and
IRS approval in 2009 to change its tax method for recognizing repair and
maintenance activities. In addition, due principally to lower gas
costs, changes in working capital generated $34.2 million of additional cash
flow year over year. These increases were offset by additional cash
uses associated with noncurrent assets and liabilities. This
increased usage is primarily related to a $23.4 million increase in pension and
other retirement plan contributions.
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.
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.
During
2009 and 2008, net cash flow associated with financing activities is reflective
of management’s ongoing effort to rely less on short-term borrowing
arrangements. The Company’s 2009 and 2008 operating cash flow funded
over 80 percent of capital expenditures and dividends in those
years. Recently completed long-term financing transactions have
allowed for the repayment of nearly $350 million in short term borrowings over
the past two years, including over $300 million repaid in 2009. In
addition, these long-term financing transactions have financed other capital
expenditures on a long-term basis. During the first quarter of 2008,
the Company mitigated its exposure to auction rate debt
markets. These transactions are more fully described
below.
Utility
Holdings 2009 Debt Issuance
On April
7, 2009, Utility Holdings entered into a private placement Note Purchase
Agreement pursuant to which institutional investors purchased from Utility
Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020
(2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’
three utilities: SIGECO, Indiana Gas, and VEDO. These
guarantees are full and unconditional and joint and several. The
proceeds from the sale of the 2020 Notes, net of issuance costs, totaled
approximately $99.5 million.
The 2020
Notes have no sinking fund requirements, and interest payments are due
semi-annually. The 2020 Notes contain customary representations,
warranties and covenants, including a leverage covenant consistent with leverage
covenants contained in the Utility Holdings’ $515 million short-term credit
facility.
Vectren
Capital Corp. 2009 Debt Issuance
On March
11, 2009, Vectren and Vectren Capital Corp., its wholly-owned subsidiary
(Vectren Capital), entered into a private placement Note Purchase Agreement (the
“2009 Note Purchase Agreement”) pursuant to which various institutional
investors purchased the following tranches of notes from Vectren Capital: (i)
$30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in
6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30
percent senior notes, Series C due 2019. These senior notes are unconditionally
guaranteed by Vectren, the parent of Vectren Capital. These notes
have no sinking fund requirements, and interest payments are due
semi-annually. The proceeds from the sale of the notes, net of
issuance costs, totaled approximately $149.0 million.
The 2009
Note Purchase Agreement contains customary representations, warranties and
covenants, including a leverage covenant consistent with leverage covenants
contained in the Vectren Capital $255 million short-term credit
facility.
On March
11, 2009, Vectren and Vectren Capital also entered into a first amendment with
respect to prior note purchase agreements for the remaining outstanding Vectren
Capital debt, other than the $22.5 million series due in 2010, to conform the
covenants in certain respects to those contained in the 2009 Note Purchase
Agreement.
SIGECO
2009 Debt Issuance
On August
19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond
issuance at an interest rate of 5.4 percent that is fixed through
maturity. The bonds mature in 2040. The proceeds from the
sale of the bonds, net of issuance costs, totaled approximately $21.3
million.
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.
On March
26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations,
receiving proceeds, net of issuance costs of approximately $40.6
million. The remarketed notes have a variable rate interest rate
which is reset weekly and are supported by a standby letter of credit backed by
Utility Holdings’ $515 million short-term credit facility. The notes
are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015
and $31.5 million are due in 2025. The initial interest rate paid to
investors was 0.55 percent. The equivalent rate of the debt at
inception, inclusive of interest, weekly remarketing fees, and letter of credit
fees, approximated 1 percent. Since Utility Holdings’ short-term
facility has a remaining term of less than one year, these obligations are
classified as Long-term debt
subject to tender in current liabilities.
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 2009 and 2008, the
Company repaid approximately $3.0 million and $1.6 million, respectively,
related to death puts. In 2007, 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 2009 (in millions) is $10.0 in 2010, $30.0 in
2011, zero in 2012 and thereafter.
Investing Cash
Flow
Cash flow
required for investing activities was $431.1 million in 2009, $402.4 million in
2008, and $303.0 million in 2007. Capital expenditures are the
primary component of investing activities and totaled $432.0 million in 2009
compared to $391.0 million in 2008 and $334.5 million in 2007. The
increase in capital expenditures in 2009 compared to 2008 reflects increased
expenditures for coal mine development and also was impacted by the January 2009
ice storm that resulted in approximately $20 million in capital
expenditures. 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 2009 and 2008
include minor acquisitions by Miller, among other items. 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”, “likely”, 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.
|
|
·
|
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.
|
|
·
|
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 recent 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; the ability to execute and negotiate new sales contracts and
resolve contract interpretations; volatile coal market prices and
demand; 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 state 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 on working capital requirements,
interest costs, and some level of price-sensitivity in volumes sold or
delivered.
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 future
periods. 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, 2009 and
2008.
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 as needed and
occasionally from other third parties in advance of usage. In the
past, the Company also used derivative financial instruments to hedge this risk,
but no such derivative instruments were outstanding at December 31, 2009 or
2008.
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 and that qualify as hedges of forecasted transactions, these
contracts are expected to be settled by physical receipt or delivery of the
commodity.
Unconsolidated
Affiliate
ProLiance,
a nonutility 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 2009 and 2008, the weighted average
combined borrowings under these arrangements approximated $211 million and $412
million, respectively. At December 31, 2009 and 2008, combined
borrowings under these arrangements were $255 million and $519 million,
respectively. Based upon average borrowing rates under these
facilities during the years ended December 31, 2009 and 2008, an increase of 100
basis points (one percentage point) in the rates would have increased interest
expense by $2.1 million and $4.1 million, respectively.
Other
Risks
By using
financial instruments to manage risk, the Company, as well as ProLiance, creates
exposure 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 uncollectible accounts expense in Ohio and the
gas cost portion of uncollectible accounts 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,
2009. Management certified this in its Sarbanes Oxley Section 302
certifications, which are attached as exhibits to this 2009 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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, 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, 2009, 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 25, 2010 expressed an
unqualified opinion on the Company’s internal control over financial
reporting.
/s/
DELOITTE & TOUCHE LLP
Indianapolis,
Indiana
February
25, 2010
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, 2009, 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, 2009, 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, 2009 of
the Company and our report dated February 25, 2010 expressed an unqualified
opinion on those financial statements and financial statement
schedule.
/s/
DELOITTE & TOUCHE LLP
Indianapolis,
Indiana
February
25, 2010
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
|
|
CONSOLIDATED
BALANCE SHEETS
|
(In
millions)
|
At December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
& cash equivalents
|
$ | 11.9 | $ | 93.2 | ||||
|
Accounts
receivable - less reserves of $5.2 &
|
||||||||
|
$5.6,
respectively
|
162.4 | 226.7 | ||||||
|
Accrued
unbilled revenues
|
144.7 | 197.0 | ||||||
|
Inventories
|
167.8 | 131.0 | ||||||
|
Recoverable
fuel & natural gas costs
|
- | 3.1 | ||||||
|
Prepayments
& other current assets
|
95.1 | 124.6 | ||||||
|
Total
current assets
|
581.9 | 775.6 | ||||||
|
Utility
Plant
|
||||||||
|
Original
cost
|
4,601.4 | 4,335.3 | ||||||
|
Less: accumulated
depreciation & amortization
|
1,722.6 | 1,615.0 | ||||||
|
Net
utility plant
|
2,878.8 | 2,720.3 | ||||||
|
Investments
in unconsolidated affiliates
|
186.2 | 179.1 | ||||||
|
Other
utility & corporate investments
|
33.2 | 25.7 | ||||||
|
Other
nonutility investments
|
46.2 | 45.9 | ||||||
|
Nonutility
plant - net
|
482.6 | 390.2 | ||||||
|
Goodwill
- net
|
242.0 | 240.2 | ||||||
|
Regulatory
assets
|
187.9 | 216.7 | ||||||
|
Other
assets
|
33.0 | 39.2 | ||||||
|
TOTAL
ASSETS
|
$ | 4,671.8 | $ | 4,632.9 | ||||
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,
|
||||||||
|
2009
|
2008
|
|||||||
|
LIABILITIES & SHAREHOLDERS'
EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable
|
$ | 183.8 | $ | 266.1 | ||||
|
Accounts
payable to affiliated companies
|
54.1 | 75.2 | ||||||
|
Refundable
fuel & natural gas costs
|
22.3 | 4.1 | ||||||
|
Accrued
liabilities
|
174.7 | 175.0 | ||||||
|
Short-term
borrowings
|
213.5 | 519.5 | ||||||
|
Current
maturities of long-term debt
|
48.0 | 0.4 | ||||||
|
Long-term
debt subject to tender
|
51.3 | 80.0 | ||||||
|
Total
current liabilities
|
747.7 | 1,120.3 | ||||||
|
Long-term
Debt - Net of Current Maturities &
|
||||||||
|
Debt
Subject to Tender
|
1,540.5 | 1,247.9 | ||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||
|
Deferred
income taxes
|
458.7 | 353.4 | ||||||
|
Regulatory
liabilities
|
322.1 | 315.1 | ||||||
|
Deferred
credits & other liabilities
|
205.6 | 244.6 | ||||||
|
Total
deferred credits & other liabilities
|
986.4 | 913.1 | ||||||
|
Commitments
& Contingencies (Notes 5, 15-17)
|
||||||||
|
Common
Shareholders' Equity
|
||||||||
|
Common
stock (no par value) – issued & outstanding
|
||||||||
|
81.1
and 81.0, respectively
|
666.8 | 659.1 | ||||||
|
Retained
earnings
|
737.2 | 712.8 | ||||||
|
Accumulated
other comprehensive income/(loss)
|
(6.8 | ) | (20.3 | ) | ||||
|
Total
common shareholders' equity
|
1,397.2 | 1,351.6 | ||||||
|
TOTAL
LIABILITIES & SHAREHOLDERS' EQUITY
|
$ | 4,671.8 | $ | 4,632.9 | ||||
|
|
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,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Electric
utility
|
528.6 | 524.2 | 487.9 | |||||||||
|
Nonutility
revenues
|
494.3 | 527.8 | 524.6 | |||||||||
|
Total
operating revenues
|
2,088.9 | 2,484.7 | 2,281.9 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
618.1 | 983.1 | 847.2 | |||||||||
|
Cost
of fuel & purchased power
|
194.3 | 182.9 | 174.8 | |||||||||
|
Cost
of nonutility revenues
|
207.5 | 282.2 | 287.7 | |||||||||
|
Other
operating
|
514.0 | 506.3 | 456.9 | |||||||||
|
Depreciation
& amortization
|
211.9 | 192.3 | 184.8 | |||||||||
|
Taxes
other than income taxes
|
63.0 | 74.5 | 70.0 | |||||||||
|
Total
operating expenses
|
1,808.8 | 2,221.3 | 2,021.4 | |||||||||
|
OPERATING
INCOME
|
280.1 | 263.4 | 260.5 | |||||||||
|
OTHER
INCOME
|
||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
3.4 | 37.4 | 22.9 | |||||||||
|
Other
– net
|
13.7 | 2.1 | 36.7 | |||||||||
|
Total
other income
|
17.1 | 39.5 | 59.6 | |||||||||
|
Interest
expense
|
100.0 | 97.8 | 101.0 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
197.2 | 205.1 | 219.1 | |||||||||
|
Income
taxes
|
64.1 | 76.1 | 76.0 | |||||||||
|
NET
INCOME
|
$ | 133.1 | $ | 129.0 | $ | 143.1 | ||||||
|
AVERAGE
COMMON SHARES OUTSTANDING
|
80.7 | 78.3 | 75.9 | |||||||||
|
DILUTED
COMMON SHARES OUTSTANDING
|
81.0 | 78.9 | 76.6 | |||||||||
|
EARNINGS
PER SHARE OF COMMON STOCK:
|
||||||||||||
|
BASIC
|
$ | 1.65 | $ | 1.65 | $ | 1.89 | ||||||
|
DILUTED
|
$ | 1.64 | $ | 1.63 | $ | 1.87 | ||||||
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, | ||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net
income
|
$ | 133.1 | $ | 129.0 | $ | 143.1 | ||||||
|
Adjustments to
reconcile net income to cash from operating activities:
|
||||||||||||
|
Depreciation & amortization
|
211.9 | 192.3 | 184.8 | |||||||||
|
Deferred income taxes & investment tax credits
|
84.9 | 79.6 | 27.0 | |||||||||
|
Equity in earnings of unconsolidated affiliates
|
(3.4 | ) | (37.4 | ) | (22.9 | ) | ||||||
|
Provision for uncollectible accounts
|
15.1 | 16.9 | 16.6 | |||||||||
|
Expense portion of pension & postretirement benefit
cost
|
10.4 | 7.8 | 9.8 | |||||||||
|
Other non-cash charges - net
|
13.3 | 25.4 | 4.8 | |||||||||
|
Changes in working capital accounts:
|
||||||||||||
|
Accounts receivable & accrued unbilled revenue
|
96.9 | (83.0 | ) | (29.1 | ) | |||||||
|
Inventories
|
(36.1 | ) | 26.4 | 2.6 | ||||||||
|
Recoverable/refundable fuel & natural gas costs
|
21.3 | (26.2 | ) | (6.3 | ) | |||||||
|
Prepayments & other current assets
|
43.1 | 9.8 | (3.7 | ) | ||||||||
|
Accounts payable, including to affiliated companies
|
(85.8 | ) | 65.7 | 4.9 | ||||||||
|
Accrued liabilities
|
4.0 | 16.5 | 4.6 | |||||||||
|
Unconsolidated affiliate dividends
|
12.6 | 15.5 | 20.8 | |||||||||
|
Employer contributions to pension & postretirement
plans
|
(38.5 | ) | (15.1 | ) | (22.6 | ) | ||||||
|
Changes in noncurrent assets
|
0.2 | 19.6 | (21.4 | ) | ||||||||
|
Changes in noncurrent liabilities
|
(33.4 | ) | (19.6 | ) | (14.9 | ) | ||||||
|
Net
cash flows from operating activities
|
449.6 | 423.2 | 298.1 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Long-term
debt
|
312.5 | 171.4 | 16.4 | |||||||||
|
Issuance
of common stock
|
- | 124.9 | - | |||||||||
|
Dividend
reinvestment plan & other
|
5.8 | 0.9 | 5.2 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Dividends
on common stock
|
(108.6 | ) | (102.6 | ) | (96.4 | ) | ||||||
|
Retirement
of long-term debt
|
(3.5 | ) | (104.9 | ) | (23.9 | ) | ||||||
|
Other
financing activities
|
- | (0.1 | ) | (0.8 | ) | |||||||
|
Net
change in short-term borrowings
|
(306.0 | ) | (37.8 | ) | 92.2 | |||||||
|
Net
cash flows from financing activities
|
(99.8 | ) | 51.8 | (7.3 | ) | |||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Unconsolidated
affiliate distributions
|
4.6 | 0.2 | 12.7 | |||||||||
|
Other
collections
|
1.5 | 6.4 | 38.0 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(432.0 | ) | (391.0 | ) | (334.5 | ) | ||||||
|
Unconsolidated
affiliate investments
|
(0.2 | ) | (0.6 | ) | (17.5 | ) | ||||||
|
Other
investments
|
(5.0 | ) | (17.4 | ) | (1.7 | ) | ||||||
|
Net
cash flows from investing activities
|
(431.1 | ) | (402.4 | ) | (303.0 | ) | ||||||
|
Net
change in cash & cash equivalents
|
(81.3 | ) | 72.6 | (12.2 | ) | |||||||
|
Cash
& cash equivalents at beginning of period
|
93.2 | 20.6 | 32.8 | |||||||||
|
Cash
& cash equivalents at end of period
|
$ | 11.9 | $ | 93.2 | $ | 20.6 | ||||||
The accompanying notes are an integral
part of these consolidated financial statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In
millions, except per share amounts)
|
Accumulated
|
||||||||||||||||||||
|
Common
Stock
|
Other
|
|||||||||||||||||||
|
Retained
|
Comprehensive
|
|||||||||||||||||||
|
Shares
|
Amount
|
Earnings
|
Income
(Loss)
|
Total
|
||||||||||||||||
|
Balance
at January 1, 2007
|
76.1 | $ | 525.5 | $ | 643.6 | $ | 5.1 | $ | 1,174.2 | |||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net
income
|
143.1 | 143.1 | ||||||||||||||||||
|
Pension/OPEB
funded status adjustment - net of $0.5 million in tax
|
0.7 | 0.7 | ||||||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||||||
|
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 | |||||||||||||||||||
|
Uncertain
tax position accounting change (see note 8)
|
(0.1 | ) | (0.1 | ) | ||||||||||||||||
|
Common
stock:
|
||||||||||||||||||||
|
Issuance: option
exercises & dividend reinvestment plan
|
0.2 | 5.2 | 5.2 | |||||||||||||||||
|
Dividends
($1.270 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 | ||||||||||||||||||
|
Pension/OPEB
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 | |||||||||||||||||||
|
Pension/OPEB
measurement date adjustment
-
net of $1.1 million in tax (see note 9)
|
(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
($1.310 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 | ||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net
income
|
133.1 | 133.1 | ||||||||||||||||||
|
Pension/OPEB
funded status adjustment - net of $0.4 million in tax
|
0.5 | 0.5 | ||||||||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||||||
|
affiliates
- net of $8.9 million in tax
|
13.0 | 13.0 | ||||||||||||||||||
|
Total
comprehensive income
|
146.6 | |||||||||||||||||||
|
Common
stock:
|
||||||||||||||||||||
|
Issuance: option
exercises & dividend reinvestment plan
|
0.3 | 5.8 | 5.8 | |||||||||||||||||
|
Dividends
($1.345 per share)
|
(108.6 | ) | (108.6 | ) | ||||||||||||||||
|
Other
|
(0.2 | ) | 1.9 | (0.1 | ) | 1.8 | ||||||||||||||
|
Balance
at December 31, 2009
|
81.1 | $ | 666.8 | $ | 737.2 | $ | (6.8 | ) | $ | 1,397.2 | ||||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
NOTES
TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of
Operations
Vectren
Corporation (the Company or Vectren), an Indiana corporation, is an energy
holding company headquartered in Evansville, Indiana. The Company’s
wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings),
serves as the intermediate holding company for three 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. 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 567,000 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 assets 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 315,000 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
|
In
applying its accounting policies, the Company makes judgments, assumptions, and
estimates that affect the amounts reported in these consolidated financial
statements and related footnotes. Examples of transactions for which
estimation techniques are used include valuing pension and postretirement
benefit obligations, unbilled revenue, uncollectible accounts, regulatory assets
and liabilities, reclamation liabilities, and derivatives and other financial
instruments. Estimates also impact the depreciation of utility and
nonutility plant and the testing goodwill and other assets for
impairment. Recorded estimates are revised when better information
becomes available or when actual amounts can be determined. Actual
results could differ from current estimates.
Principles of
Consolidation
The
consolidated financial statements include the accounts of the Company and its
wholly owned subsidiaries, after elimination of significant intercompany
transactions.
Subsequent Events
Review
Management
performs a review of subsequent events for any events occurring after the
balance sheet date but prior to the date the financial statements are
issued.
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. Cash and cash
equivalents are stated at cost plus accrued interest to approximate fair
value.
Allowance for Uncollectible
Accounts
The
Company maintains allowances for uncollectible accounts for estimated losses
resulting from the inability of its customers to make required payments. The
Company estimates the allowance for uncollectible accounts based on a variety of
factors including the length of time receivables are past due, the financial
health of its customers, unusual macroeconomic conditions, and historical
experience. If the financial condition of its customers deteriorates
or other circumstances occur that result in an impairment of customers’ ability
to make payments, the Company records additional allowances as
needed.
Inventories
In most
circumstances, the Company’s inventory components are recorded using an average
cost method; however, natural gas in storage at the Company’s Indiana utilities
and coal inventory at the Company’s nonutility coal mines are recorded using the
Last In – First Out (LIFO) method. Inventory related to the Company’s
regulated operations is valued at historical cost consistent with ratemaking
treatment. Materials and supplies are recorded as inventory when
purchased and subsequently charged to expense or capitalized to plant when
installed. Nonutility inventory is valued at the lower of cost or
market. Inventories consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Gas
in storage – at average cost
|
$ | 22.2 | $ | 40.4 | ||||
|
Gas
in storage – at LIFO cost
|
24.4 | 22.2 | ||||||
|
Total
Gas in storage
|
46.6 | 62.6 | ||||||
|
Materials
& supplies
|
42.6 | 33.4 | ||||||
|
Coal
& Oil for electric generation - at average cost
|
66.8 | 28.4 | ||||||
|
Coal
- at LIFO cost
|
8.5 | 3.3 | ||||||
|
Other
|
3.3 | 3.3 | ||||||
|
Total
inventories
|
$ | 167.8 | $ | 131.0 | ||||
Based on
the average cost of gas purchased and coal produced during December, the cost of
replacing inventories carried at LIFO cost exceeded that carrying value at
December 31, 2009, and 2008, by approximately $21 million and $36 million,
respectively.
Property, Plant, &
Equipment
Both the
Company’s Utility Plant
and Nonutility Plant is
stated at historical cost, inclusive of financing costs and direct and indirect
construction costs, less accumulated depreciation and when necessary, impairment
charges. The cost of renewals and betterments that extend the useful
life are capitalized. Maintenance and repairs, including the cost of
removal of minor items of property and planned major maintenance projects, are
charged to expense as incurred.
Impairment
Reviews
Property,
plant and equipment along with other long-lived assets are reviewed as facts and
circumstances indicate that the carrying amount may be impaired. This
impairment review involves the comparison of an asset’s (or group of assets’)
carrying value to the estimated future cash flows the asset (or asset group) is
expected to generate over a remaining life. If this evaluation were
to conclude that the carrying value is impaired, an impairment charge would be
recorded based on the difference between the 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.
Utility
Plant & Related Depreciation
Both the
IURC and PUCO allow the Company’s utilities to capitalize financing costs
associated with Utility
Plant based on a computed interest cost and a designated cost of equity
funds. These financing costs are commonly referred to as AFUDC and
are capitalized for ratemaking purposes and for financial reporting purposes
instead of amounts that would otherwise be capitalized when acquiring nonutility
plant. The Company reports both the debt and equity components of
AFUDC in Other – net in
the Consolidated Statements of
Income.
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,
resulting in no gain or loss. Costs to dismantle and remove retired
property are recovered through the depreciation rates as determined by the IURC
and PUCO.
The
Company’s portion of jointly owned Utility Plant, along with
that plant’s related operating expenses, is presented in these financial
statements in proportion to the ownership percentage.
Nonutility
Plant & Related Depreciation
The
depreciation of Nonutility
Plant is charged against income over its estimated useful life, using the
straight-line method of depreciation or units-of-production method of
amortization for certain coal mining assets. 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, typically
impacting operating expenses.
Investments in
Unconsolidated Affiliates
Investments in unconsolidated
affiliates where the Company has significant influence are accounted for
using the equity method of accounting. The Company’s share of net
income or loss from these investments is recorded in Equity in earnings of unconsolidated
affiliates. Dividends are recorded as a reduction of the
carrying value of the investment when received. Investments in unconsolidated
affiliates where the Company does not have significant influence are
accounted for using the cost method of accounting. Dividends
associated with cost method investments are recorded as Other – net when
received. Investments, when necessary, include adjustments for
declines in value judged to be other than temporary. Investments in unconsolidated
affiliates consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
ProLiance
Holdings, LLC
|
$ | 167.9 | $ | 153.1 | ||||
|
Haddington
Energy Partnerships
|
9.3 | 13.9 | ||||||
|
Other
partnerships & corporations
|
9.0 | 12.1 | ||||||
|
Total
investments in unconsolidated affiliates
|
$ | 186.2 | $ | 179.1 | ||||
Equity in earnings of unconsolidated affiliates consists of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
ProLiance
Holdings , LLC
|
$ | 3.6 | $ | 39.5 | $ | 41.0 | ||||||
|
Haddinton
Energy Partners, LP
|
0.9 | (0.2 | ) | (0.2 | ) | |||||||
|
Pace
Carbon Synfuels, LP
|
- | - | (20.0 | ) | ||||||||
|
Other
|
(1.1 | ) | (1.9 | ) | 2.1 | |||||||
|
Total
equity in earnings of unconsolidated affiliates
|
$ | 3.4 | $ | 37.4 | $ | 22.9 | ||||||
Goodwill
Goodwill recorded on the
Consolidated Balance
Sheets results from business acquisitions and is based on a fair value
allocation of the businesses’ purchase price at the time of
acquisition. Goodwill is 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. As of December 31, 2009 and 2008
goodwill by operating segment follows:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Utility
Group
|
||||||||
|
Gas
Utility Services
|
$ | 205.0 | $ | 205.0 | ||||
|
Nonutility
Group
|
37.0 | 35.2 | ||||||
|
Consolidated
goodwill
|
$ | 242.0 | $ | 240.2 | ||||
No
goodwill impairments have been recorded during the periods
presented.
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 ratemaking and accounting practices authorized by these
agencies.
Refundable
or Recoverable Gas Costs & 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 and
purchased power for electric generation is charged to operating expense when
consumed.
Regulatory
Assets & 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 continually assesses the recoverability of costs
recognized as regulatory assets and liabilities and the ability to recognize new
regulatory assets and liabilities associated with its regulated utility
operations. Given the current regulatory environment in its
jurisdictions, the Company believes such accounting is appropriate.
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.
Postretirement Obligations
& Costs
The
Company recognizes the funded status of its pension plans and postretirement
plans on its balance sheet date. The funded status of a defined
benefit plan is its assets (if any) less its projected benefit obligation (PBO),
which reflects service accrued to date and includes the impact of projected
salary increases (for pay –related benefits). The funded status of a
postretirement plan is its assets (in any) less its accumulated postretirement
benefit obligation (APBO), which reflects accrued service to date. To
the extent this obligation exceeds amounts previously recognized in the
statement of income, 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.
The
annual cost of all post retirement plans is recognized in operating expenses or
capitalized to plant following the direct labor of current
employees. Specific to pension plans, the Company uses the projected
unit credit actuarial cost method to calculate service cost and the
PBO. This method projects the present value of benefits at retirement
and allocates that cost over the projected years of service. Annual
service cost represents one year’s benefit accrual while the PBO represents
benefits allocated to previously accrued service. For other
postretirement plans, service cost is calculated by dividing the present value
of a participant’s projected postretirement benefits into equal parts based upon
the number of years between a participant’s hire date and first eligible
retirement date. Annual service cost represents one year’s benefit
accrual while the APBO represents benefit allocated to previously accrued
service. To calculate the expected return on pension 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. Interest cost represents
the annual accretion of the PBO and APBO at the discount
rate. Actuarial gains and losses outside of a corridor (equal to 10%
of the greater of the benefit obligation and the market-related value of assets)
are amortized over the expected future working lifetime of active participants
(except for plans where almost all participants are inactive). Prior
service costs related to plan changes are amortized over the expected future
working lifetime (or to full eligibility date for postretirement plan other than
pensions) of the active participants at the time of the amendment.
Asset Retirement
Obligations
A portion
of removal costs related to interim retirements of gas utility pipeline and
utility poles, certain asbestos-related issues, and reclamation activities meet
the definition of an asset retirement obligation (ARO). The Company
records 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 Company
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, the Company settles the obligation for its recorded
amount or incurs a gain or loss. To the extent regulation is
involved, regulatory assets and liabilities result when accretion and
amortization is adjusted to match rates established by regulators and any gain
or loss is subject to deferral.
ARO’s
included in Other
liabilities total $33.1 million and $27.5 million at December 31, 2009
and 2008, respectively. ARO’s included in Accrued liabilities total
$3.0 million and $7.2 million at December 31, 2009 and 2008,
respectively. During 2009, the Company recorded accretion of $1.5
million and decreases in estimates, net of cash payments of $0.1
million. During 2008, the Company recorded accretion of $1.1 million
and increases in estimates, net of cash payments of $5.2 million.
Product Warranties,
Performance Guarantees, & Other Guarantees
Liabilities
and expenses associated with product warranties and performance guarantees are
recognized based on historical experience at the time the associated revenue is
recognized. Adjustments are made as changes become reasonably
estimable. The Company does not recognize the fair value of an
obligation at inception for these guarantees because they are guarantees of the
Company’s own performance and/or product installations.
While not
significant at December 31, 2009 or 2008, the Company does recognize the fair
value of an obligation at the inception of a guarantee in certain
circumstances. These circumstances would include executing certain
indemnification agreements and guaranteeing operating lease residual values, the
performance of a third party, or the indebtedness of a third party.
Energy Contracts &
Derivatives
The
Company occasionally 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. In most cases, a
derivative is recognized on the balance sheet as an asset or liability measured
at its fair market value and the change in the derivative's fair market value is
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 (NPNS), it is exempted from mark-to-market
accounting. Most energy contracts executed by the Company are subject
to the NPNS exclusion or are not considered derivatives. Such energy
contracts include Real Time and Day Ahead purchase and sale contracts with the
MISO, natural gas purchases from ProLiance and others, and wind farm and other
electric generating capacity contracts.
When the
Company engages in energy contracts and financial contracts that are derivatives
and are not subject to the NPNS or other exclusions, such contracts 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 regulatory accounting treatment. 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 regulatory accounting
treatment are marked to market as a regulatory asset or
liability. Market value for derivative contracts is determined using
quoted market prices from independent sources. The Company rarely
enters into contracts that have a significant impact to the financial statements
where internal models are used to calculate fair value. As of and for
the periods presented, related derivative activity is not significant to these
financial statements.
Revenues
Most
revenues are recorded as products and services are delivered to
customers. 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.
Share-Based
Compensation
The
Company grants share-based compensation to certain employees and board
members. Liability classified share-based compensation awards are
re-measured at the end of each period based on their expected settlement date
fair value. Equity classified stock-based compensation awards are
measured at the grant date, based on the fair value of the
award. Expense associated with share-based awards is recognized over
the requisite service period, which generally begins on the date the award is
granted through the earlier of the date the award vests or the date the employee
becomes retirement eligible.
Excise & 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 $36.3 million in 2009, $45.0
million in 2008, and $41.8 million in 2007. Expense associated with
excise and utility receipts taxes are recorded as a component of Taxes other than income
taxes.
Operating
Segments
The
Company’s chief operating decision maker is comprised of a group of executive
management led by the Chief Executive Officer. The Company uses net
income calculated in accordance with generally accepted accounting principles as
its most relevant performance measure. The Company has three
operating segments within its Utility Group, one operating segment in its
Nonutility Group, and a Corporate and Other segment.
Fair Value
Measurements
Certain
financial assets and liabilities as well as certain nonfinancial assets and
liabilities, such as the initial measurement of an asset retirement obligation
or the use of fair value in goodwill, intangible assets and long-lived assets
impairment tests, are valued and/or disclosed at fair value. The
Company describes its fair value measurements using a hierarchy of inputs based
primarily on the level of public data used. 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 using internal models, which reflect what a market
participant would use to determine fair value.
|
3.
|
Utility
& Nonutility Plant
|
The
original cost of Utility
Plant, together with depreciation rates expressed as a percentage of
original cost, follows:
|
At
December 31,
|
|||||||||||||||||
|
(In
millions)
|
2009
|
2008
|
|||||||||||||||
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
||||||||||||||
|
Gas
utility plant
|
$ | 2,299.1 | 3.5 | % | $ | 2,157.6 | 3.5 | % | |||||||||
|
Electric
utility plant
|
2,113.3 | 3.4 | % | 1,884.3 | 3.3 | % | |||||||||||
|
Common
utility plant
|
48.7 | 2.9 | % | 47.9 | 2.9 | % | |||||||||||
|
Construction
work in progress
|
140.3 | - | 245.5 | - | |||||||||||||
|
Total
original cost
|
$ | 4,601.4 | $ | 4,335.3 | |||||||||||||
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, 2009, is $178.1 million with
accumulated depreciation totaling $53.4 million. The construction
work-in-progress balance associated with SIGECO’s ownership interest totaled
$0.7 million at December 31, 2009. 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.
Nonutility plant, net of
accumulated depreciation and amortization follows:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Computer
hardware & software
|
$ | 119.9 | $ | 129.6 | ||||
|
Land
& buildings
|
115.1 | 93.9 | ||||||
|
Coal
mine development costs & equipment
|
188.6 | 109.1 | ||||||
|
Vehicles
& equipment
|
43.7 | 41.7 | ||||||
|
All
other
|
15.3 | 15.9 | ||||||
|
Nonutility
plant - net
|
$ | 482.6 | $ | 390.2 | ||||
Nonutility
plant is presented net of accumulated depreciation and amortization totaling
$334.3 million and $281.6 million as of December 31, 2009 and 2008,
respectively. For the years ended December 31, 2009, 2008, and 2007,
the Company capitalized interest totaling $6.0 million, $3.7 million, and $2.3
million, respectively, on nonutility plant construction projects.
|
4.
|
Regulatory
Assets & Liabilities
|
Regulatroy Assets
Regulatory assets consist of
the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Future
amounts recoverable from ratepayers related to:
|
||||||||
|
Benefit
obligations
|
$ | 83.9 | $ | 101.0 | ||||
|
Deferred
Income taxes
|
14.7 | 11.4 | ||||||
|
Asset
retirement obligations & other
|
4.2 | 8.5 | ||||||
| 102.8 | 120.9 | |||||||
|
Amounts
deferred for future recovery related to:
|
||||||||
|
Cost
recovery riders & other
|
1.0 | 1.7 | ||||||
| 1.0 | 1.7 | |||||||
|
Amounts
currently recovered in customer rates related to:
|
||||||||
|
Demand
side management programs
|
15.3 | 21.5 | ||||||
|
Unamortized
debt issue costs & hedging proceeds
|
38.1 | 38.4 | ||||||
|
Indiana
authorized trackers
|
15.6 | 13.8 | ||||||
|
Ohio
authorized trackers
|
8.2 | 11.6 | ||||||
|
Premiums
paid to reacquire debt & other
|
6.9 | 8.8 | ||||||
| 84.1 | 94.1 | |||||||
|
Total
regulatory assets
|
$ | 187.9 | $ | 216.7 | ||||
Of the $84.1 million currently being recovered in customer rates, $15.3 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 11 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, 2009 and 2008, the Company has approximately $322.1 million and
$315.1 million, respectively, in Regulatory
liabilities. Of these amounts, $294.4 million and $292.4
million relate to cost of removal obligations. The remaining amounts
primarily relate to timing differences associated with asset retirement
obligations and deferred financing costs.
|
5.
|
Investment
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
approximately 75 percent of its natural gas purchases through ProLiance in 2009,
2008, and 2007.
Summarized Financial
Information
|
Year
Ended December 31,
|
||||||||||||
|
(in
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Summarized
Statement of Income information:
|
||||||||||||
|
Revenues
|
$ | 1,654.9 | $ | 2,883.6 | $ | 2,267.1 | ||||||
|
Operating
income
|
35.2 | 63.7 | 61.5 | |||||||||
|
Charge
related to Investment in Liberty Gas Storage
|
(32.7 | ) | - | - | ||||||||
|
ProLiance's
earnings
|
4.5 | 64.7 | 67.2 | |||||||||
|
As
of December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Summarized
balance sheet information:
|
||||||||
|
Current
assets
|
$ | 477.6 | $ | 661.5 | ||||
|
Noncurrent
assets
|
61.7 | 104.2 | ||||||
|
Current
liabilities
|
264.5 | 514.0 | ||||||
|
Noncurrent
liabilities
|
4.0 | 3.6 | ||||||
|
Members'
equity
|
282.4 | 295.8 | ||||||
|
Accumulated other
comprehensive income (loss)
|
(11.6 | ) | (47.7 | ) | ||||
Vectren
records its 61 percent share of ProLiance’s earnings after income taxes and an
interest expense allocation.
Regulatory Matter
Resolved
ProLiance
self reported to the 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. During the second quarter of 2009, ProLiance resolved the
matter with FERC. The amount of the penalty was not material to the
Company’s consolidated operating results, financial position or cash
flows.
Investment in Liberty Gas
Storage
Liberty
Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance
and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern
natural gas storage facilities. ProLiance is the minority member with a 25
percent interest, which it accounts for using the equity method. The
project was expected to include 17 Bcf of capacity in its north facility
(previously referred to as the Sulfur site, located near Sulfur, Louisiana), and
an additional 17 Bcf of capacity in its south facility (previously referred to
as the Hackberry site, near Hackberry, Louisiana). As more fully described
below, it is now expected that only the south facility will be completed by the
joint venture. This facility is expected to provide at least 17 Bcf of capacity.
The Liberty pipeline system is currently connected with several interstate
pipelines, including the Cameron Interstate Pipeline operated by Sempra
Pipelines & Storage, and will connect area LNG regasification terminals to
an interstate natural gas transmission system and storage
facilities. ProLiance’s investment in Liberty is $37.3 million at
December 31, 2009, after reflecting the charge discussed below.
In late
2008, SE advised ProLiance that the completion of the phase of Liberty’s
development at the north site had been delayed by subsurface and well-completion
problems. Based on testing performed in the second quarter of 2009, SE
determined that attempts at corrective measures had been unsuccessful in
development of certain caverns. At June 30, 2009, Liberty recorded a
charge of approximately $132 million to write off the north caverns and certain
related assets. As an equity investor in Liberty, ProLiance recorded
its share of the charge, totaling $33 million at June 30, 2009. The
Company’s share is $11.9 million after tax, or $0.15 per share. In the Consolidated Statement of
Income for the year ended December 31, 2009, the charge is an approximate
$19.9 million reduction to Equity in earnings of unconsolidated
affiliates and an income tax benefit reflected in Income taxes of approximately
$8.0 million. The charge is not material to the Company’s financial
condition. ProLiance does not expect it to impact its future
liquidity or access to capital, nor is it expected that this situation will
impact ProLiance’s ability to meet the needs of its customers.
Transactions with
ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2009, 2008, and 2007, totaled $533.4 million, $940.1 million, and
$792.4 million, respectively. Amounts owed to ProLiance at December
31, 2009, and 2008, for those purchases were $54.1 million and $75.1 million,
respectively, and are included in Accounts payable to affiliated
companies in the Consolidated Balance
Sheets. 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. Amounts charged by
ProLiance for gas supply services are established by supply agreements with each
utility.
Undistributed
Earnings
As of
December 31, 2009, undistributed earnings of unconsolidated affiliates
approximated $154 million and are primarily comprised of the undistributed
earnings of ProLiance.
|
6.
|
Nonutility
Real Estate & 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, 2009 and 2008, total remaining
legacy investments included in the Other Businesses portfolio total $64.5
million and $71.8 million, respectively. Further separation of that
2009 investment by type of investment follows:
|
December
31, 2009
|
||||||||||||
|
Value
Included In
|
||||||||||||
|
(in
millions)
|
Carrying
Value
|
Other
Nonutility Investments
|
Investments
in Unconsolidated Affiliates
|
|||||||||
|
Commercial
real estate investments
|
$ | 21.0 | $ | 21.0 | $ | - | ||||||
|
Leveraged
leases
|
17.5 | 17.5 | - | |||||||||
|
Haddington
energy partnerships
|
9.7 | 0.4 | 9.3 | |||||||||
|
Affordable
housing projects
|
7.8 | 0.1 | 7.7 | |||||||||
|
Other
investments
|
8.5 | 7.2 | 1.3 | |||||||||
| $ | 64.5 | $ | 46.2 | $ | 18.3 | |||||||
Commercial Real Estate
Charge
The
recent recession 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. Of the $10.0 million charge, $5.2 million is included in
Other-net and $4.8
million is included in Other
operating expenses. The impairment impacted the carrying
values of primarily notes receivable collateralized by commercial real estate
and an office building of which the Company took possession when a leveraged
lease expired in 2008 and that is currently for sale.
Notes
Receivable
At both
December 31, 2009 and 2008, notes receivable, inclusive of accrued interest and
net of reserves, totaled $16.7 million. Of the $46.2 million in Other nonutility investments
identified above, notes receivable comprise approximately $10 million of the
Commercial real estate investments and $6 million of the Other
investments. A reserve for potential uncollectible notes as of
December 31, 2009 and 2008 totaled $9.2 million and $6.3 million,
respectively. As of December 31, 2009, the Company is recognizing
interest on the cash basis for substantially the entire note
portfolio. Such interest income has been insignificant during the
past three years. Second mortgages serve as collateral for notes
associated with the commercial real estate investments.
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,
2009. 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 $49.2 million at December
31, 2009. At December 31, 2009, the Company’s $17.5 million leveraged
lease investment when netted against related deferred tax liabilities was $2.8
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, 2009, these Haddington
ventures have interests in two remaining mid-stream energy related
investments. 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,
2009, revenues, operating loss, and net income were (in millions) zero, $(0.4),
and $7.9, respectively. 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. As of December 31, 2009, investments, other assets, and
liabilities were (in millions) $26.4, zero, and zero,
respectively. As of December 31, 2008, investments, other assets, and
liabilities were (in millions) $32.0, $0.5, and $0.1, respectively.
Variable Interest
Entities
Some of
these legacy nonutility investments are partnership-like structures involved in
activities surrounding multifamily housing and office properties and are
variable interest entities. The Company is either a limited partner
or a subordinated lender and does not consolidate any of these
entities. The Company’s exposure to loss is limited to its investment
which as of December 31, 2009, and 2008, totaled $7.7 million and $9.5 million,
respectively, recorded in Investments in unconsolidated
affiliates, and $10.1 million for each year recorded in Other nonutility
investments.
|
7.
|
Intangible
Assets
|
Intangible
assets, which are included in Other assets, consist of the
following:
|
(In
millions)
|
At
December 31,
|
|||||||||||||||
|
2009
|
2008
|
|||||||||||||||
|
Amortizing
|
Non-amortizing
|
Amortizing
|
Non-amortizing
|
|||||||||||||
|
Customer-related
assets
|
$ | 8.0 | $ | - | $ | 8.9 | $ | - | ||||||||
|
Market-related
assets
|
- | 7.0 | 0.1 | 7.0 | ||||||||||||
|
Intangible
assets, net
|
$ | 8.0 | $ | 7.0 | $ | 9.0 | $ | 7.0 | ||||||||
As of
December 31, 2009, 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 $2.8 million for customer-related assets and $0.2 million
for market-related assets at December 31, 2009 and $2.6 million for
customer-related assets and $0.2 million for market-related assets at December
31, 2008. In 2009, 2008, and 2007, amortization associated with
intangible assets was $0.6 million, $0.6 million and $0.7 million,
respectively. Amortization should approximate that incurred in 2009
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 $1.3 million and $1.6 million at December 31, 2009 and 2008,
respectively. The value of the emission allowances are recognized as
they are consumed or sold.
|
8.
|
Income
Taxes
|
Deferred
income taxes are provided for temporary differences between the tax basis
(adjusted for related unrecognized tax benefits, if any) of an asset or
liability and its reported amount in the financial statements. Deferred
tax assets and liabilities are computed based on the currently-enacted statutory
income tax rates that are expected to be applicable when the temporary
differences are scheduled to reverse. The Company’s rate-regulated
utilities recognize regulatory liabilities for deferred taxes provided in excess
of the current statutory tax rate and regulatory assets for deferred taxes
provided at rates less than the current statutory tax rate. Such
tax-related regulatory assets and liabilities are reported at the revenue
requirement level and amortized to income as the related temporary differences
reverse, generally over the lives of the related properties. A valuation
allowance is recorded to reduce the carrying amounts of deferred tax assets
unless it is more likely than not that the deferred tax assets will be
realized.
Tax
benefits associated with income tax positions taken, or expected to be taken, in
a tax return are recorded only when the more-likely-than-not recognition
threshold is satisfied and measured at the largest amount of benefit that is
greater than 50 percent likely of being realized upon settlement. The
Company reports interest and penalties associated with unrecognized tax benefits
within Income taxes in
the Consolidated Statements of
Income and reports tax liabilities related to unrecognized tax benefits
as part of Deferred credits
& other
liabilities.
Investment
tax credits (ITCs) are deferred and amortized to income over the approximate
lives of the related property in accordance with the regulatory
treatment. Production tax credits (PTCs) are recognized as energy is
generated and sold based on a per kilowatt hour rate prescribed in applicable
federal and state statutes.
Significant
components of the net deferred tax liability follow:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Noncurrent
deferred tax liabilities (assets):
|
||||||||
|
Depreciation
& cost recovery timing differences
|
$ | 483.3 | $ | 372.6 | ||||
|
Leveraged
leases
|
14.7 | 15.1 | ||||||
|
Regulatory
assets recoverable through future rates
|
25.6 | 27.8 | ||||||
|
Other
comprehensive income
|
(5.7 | ) | (15.0 | ) | ||||
|
Alternative
minimum tax carryforward
|
(21.6 | ) | - | |||||
|
Employee
benefit obligations
|
(24.0 | ) | (36.2 | ) | ||||
|
Net
operating loss & other carryforwards
|
(0.5 | ) | (2.1 | ) | ||||
|
Regulatory
liabilities to be settled through future rates
|
(11.7 | ) | (15.7 | ) | ||||
|
Other
– net
|
(1.4 | ) | 6.9 | |||||
|
Net
noncurrent deferred tax liability
|
458.7 | 353.4 | ||||||
|
Current
deferred tax (assets)/liabilities:
|
||||||||
|
Deferred
fuel costs-net
|
1.2 | 2.6 | ||||||
|
Demand
side management programs
|
5.2 | 8.8 | ||||||
|
Alternative
minimum tax carryforward
|
(15.8 | ) | (11.2 | ) | ||||
|
Other
– net
|
(12.3 | ) | (8.4 | ) | ||||
|
Net
current deferred tax asset
|
(21.7 | ) | (8.2 | ) | ||||
|
Net
deferred tax liability
|
$ | 437.0 | $ | 345.2 | ||||
At
December 31, 2009 and 2008, investment tax credits totaling $5.8 million and
$6.9 million, respectively, are included in Deferred credits & other
liabilities. At December 31, 2009, the Company has alternative
minimum tax carryforwards which do not expire. In addition, the
Company has $0.2 million in net operating loss carryforwards that relate to the
acquisition of Miller, which will expire in 5 to 20 years. A reconciliation of
the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||
|
2009
|
2008
|
2007
|
||||||||
|
Statutory
rate:
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
||||
|
State
& local taxes-net of federal benefit
|
2.3
|
3.9
|
4.3
|
|||||||
|
Amortization of
investment tax credit
|
(0.5)
|
(0.6)
|
(0.8)
|
|||||||
|
Depletion
|
(2.0)
|
(0.4)
|
(0.7)
|
|||||||
|
Other
tax credits
|
(0.2)
|
(0.9)
|
(0.2)
|
|||||||
|
Synfuel
tax credits
|
-
|
-
|
(3.0)
|
|||||||
|
Adjustment of
income tax accruals
|
(2.1)
|
-
|
0.2
|
|||||||
|
All
other-net
|
-
|
0.1
|
(0.1)
|
|||||||
|
Effective
tax rate
|
32.5
|
%
|
37.1
|
%
|
34.7
|
%
|
||||
The
components of income tax expense and utilization of investment tax credits
follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | (21.4 | ) | $ | (14.8 | ) | $ | 35.9 | ||||
|
State
|
0.6 | 11.3 | 13.1 | |||||||||
|
Total
current taxes
|
(20.8 | ) | (3.5 | ) | 49.0 | |||||||
|
Deferred:
|
||||||||||||
|
Federal
|
78.7 | 78.2 | 24.6 | |||||||||
|
State
|
7.3 | 2.7 | 4.1 | |||||||||
|
Total
deferred taxes
|
86.0 | 80.9 | 28.7 | |||||||||
|
Amortization
of investment tax credits
|
(1.1 | ) | (1.3 | ) | (1.7 | ) | ||||||
|
Total
income tax expense
|
$ | 64.1 | $ | 76.1 | $ | 76.0 | ||||||
Uncertain Tax
Positions
Following
is a roll forward of the total amount of unrecognized tax benefits for the three
years ended December 31, 2009 and 2008:
|
(in
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Unrecognized
tax benefits at January 1
|
$ | 2.2 | $ | 6.2 | $ | 11.6 | ||||||
|
Gross increases -
tax positions in prior periods
|
1.1 | 1.7 | 0.3 | |||||||||
|
Gross decreases -
tax positions in prior periods
|
(1.8 | ) | (6.0 | ) | (7.4 | ) | ||||||
|
Gross increases -
current period tax positions
|
9.0 | 0.3 | 1.9 | |||||||||
|
Gross decreases -
current period tax positions
|
- | - | (0.2 | ) | ||||||||
|
Settlements
|
(0.1 | ) | - | - | ||||||||
|
Lapse of statute of
limitations
|
1.1 | - | - | |||||||||
|
Unrecognized
tax benefits at December 31
|
$ | 11.5 | $ | 2.2 | $ | 6.2 | ||||||
Of the
change in unrecognized tax benefits during 2009, 2008, and 2007, almost none
impacted the effective rate. The amount of unrecognized tax benefits,
which if recognized, that would impact the effective tax rate was $0.5 million
at both December 31, 2009 and 2008 and $0.1 million at December 31,
2007.
As of
December 31, 2009, the 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 recognized expense related to interest and penalties totaling
approximately $0.2 million in 2009 and less than $0.1 million in
2008. During the year ended December 31, 2007, the Company recognized
expense related to interest and penalties of approximately $0.5
million. The Company had approximately $0.6 million and $0.8 million
for the payment of interest and penalties accrued as of December 31, 2009 and
2008, respectively.
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 income taxes and are
benefits, totaled $7.9 million and $0.8 million, respectively, at December 31,
2009 and 2008.
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.
As the
result of adopting changes to the accounting guidance for uncertain tax
positions on January 1, 2007, 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.
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, 2007. The
statutes of limitations for assessment of federal and Indiana income tax have
expired with respect to tax years through
2002.
|
9.
|
Retirement
Plans & Other Postretirement
Benefits
|
At
December 31, 2009, 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.”
Measurement Date
Change
Prior to
2008, the Company measured obligations as of September 30. The
Company changed its measurement date due to a required change in the accounting
rules. The effects of moving the measurement date 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, directly to Retained earnings on January
1, 2008. Related adjustments to Accumulated other comprehensive
income and Regulatory
assets were not material.
-76-
Net Periodic Benefit
Costs
A summary
of the components of net periodic benefit cost for the three years ended
December 31, 2009 follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||||||||||||
|
Service
cost
|
$ | 6.3 | $ | 6.1 | $ | 5.6 | $ | 0.5 | $ | 0.5 | $ | 0.5 | ||||||||||||
|
Interest
cost
|
15.8 | 15.1 | 14.9 | 4.4 | 4.2 | 4.0 | ||||||||||||||||||
|
Expected
return on plan assets
|
(16.4 | ) | (16.6 | ) | (14.3 | ) | (0.3 | ) | (0.5 | ) | (0.5 | ) | ||||||||||||
|
Amortization
of prior service cost (benefit)
|
1.7 | 1.7 | 1.7 | (0.8 | ) | (0.8 | ) | (0.8 | ) | |||||||||||||||
|
Amortization
of actuarial loss (gain)
|
2.2 | 0.1 | 1.5 | 0.4 | - | (0.1 | ) | |||||||||||||||||
|
Amortization
of transitional obligation
|
- | - | - | 1.1 | 1.1 | 1.1 | ||||||||||||||||||
|
Net
periodic benefit cost
|
$ | 9.6 | $ | 6.4 | $ | 9.4 | $ | 5.3 | $ | 4.5 | $ | 4.2 | ||||||||||||
A portion
of benefit costs are capitalized as Utility
plant. Costs capitalized in 2009, 2008, and 2007 are estimated
at $4.5 million, $3.0 million, and $3.9 million, respectively.
The
Company has used a long-term expected rate of return of 8.25 percent to
calculate 2009 periodic benefit cost. For fiscal year 2010, the
expected long-term rate of return will be 8 percent.
The
Company maintained a consistent discount rate of 6.25 percent to measure
periodic cost due to minimal changes in December 31, 2009 and 2008 benchmark
interest rates that approximate the expected duration of the Company’s benefit
obligations. For fiscal year 2010, the discount rate will be 6
percent.
The
weighted averages of significant assumptions used to determine net periodic
benefit costs follow:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||
|
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||
|
Discount
rate
|
6.25%
|
6.25%
|
5.85%
|
6.25%
|
6.25%
|
5.85%
|
|||||||
|
Rate
of compensation increase
|
3.75%
|
3.75%
|
3.75%
|
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%
|
|||||||
Benefit
Obligations
A
reconciliation of the Company’s benefit obligations at December 31, 2009 and
2008 follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Benefit
obligation, beginning of period
|
$ | 260.6 | $ | 249.6 | $ | 72.3 | $ | 70.2 | ||||||||
|
Service
cost – benefits earned during the period
|
6.3 | 7.7 | 0.5 | 0.7 | ||||||||||||
|
Interest
cost on projected benefit obligation
|
15.8 | 18.8 | 4.4 | 5.2 | ||||||||||||
|
Plan
participants' contributions
|
- | - | 2.8 | 2.8 | ||||||||||||
|
Plan
amendments
|
0.1 | 0.4 | - | - | ||||||||||||
|
Actuarial
loss (gain)
|
2.0 | 0.3 | 7.2 | 2.5 | ||||||||||||
|
Medicare
subsidy receipts
|
- | - | 0.8 | 0.7 | ||||||||||||
|
Benefits
paid
|
(13.3 | ) | (16.2 | ) | (8.4 | ) | (9.8 | ) | ||||||||
|
Benefit
obligation, end of period
|
$ | 271.5 | $ | 260.6 | $ | 79.6 | $ | 72.3 | ||||||||
The
accumulated benefit obligation for all defined benefit pension plans was $257.0
million and $245.2 million at December 31, 2009 and 2008,
respectively. Due to moving the measurement date from September 30 to
December 31, the 2008 roll forward of the projected benefit obligation includes
15 months of activity.
The
benefit obligation as of December 31, 2009 and 2008 was calculated using the
following assumptions:
|
Pension
Benefits
|
Other
Benefits
|
||||||||
|
2009
|
2008
|
2009
|
2008
|
||||||
|
Discount
rate
|
6.00%
|
6.25%
|
6.00%
|
6.25%
|
|||||
|
Rate
of compensation increase
|
3.50%
|
3.75%
|
N/A
|
N/A
|
|||||
|
Expected
increase in Consumer Price Index
|
N/A
|
N/A
|
3.00%
|
3.50%
|
|||||
To
calculate the 2009 ending postretirement benefit obligation, medical claims
costs in 2010 were assumed to be 9 percent higher than those incurred in
2009. That trend was assumed to reach its ultimate trending increase
of 5 percent by 2014 and remain level thereafter. A one-percentage
point change in assumed health care cost trend rates would have changed the
benefit obligation by approximately $2.5 million.
Plan
Assets
A
reconciliation of the Company’s plan assets at December 31, 2009 and 2008
follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Plan
assets at fair value, beginning of period
|
$ | 150.9 | $ | 211.8 | $ | 4.3 | $ | 6.8 | ||||||||
|
Actual
return on plan assets
|
38.6 | (58.0 | ) | 0.9 | (1.4 | ) | ||||||||||
|
Employer
contributions
|
34.9 | 13.3 | 4.4 | 5.9 | ||||||||||||
|
Plan
participants' contributions
|
- | - | 2.8 | 2.8 | ||||||||||||
|
Benefits
paid
|
(13.3 | ) | (16.2 | ) | (8.4 | ) | (9.8 | ) | ||||||||
|
Fair
value of plan assets, end of period
|
$ | 211.1 | $ | 150.9 | $ | 4.0 | $ | 4.3 | ||||||||
Due to
moving the measurement date from September 30 to December 31, the 2008 roll
forward of plan assets includes 15 months of activity.
The
Company’s overall investment strategy for its retirement plan trusts is maintain
investments in a diversified portfolio, comprised of primarily 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 investments, including real estate. The both the
equity and debt securities have a blend of domestic and international
exposures. For other benefit plans the targeted allocation is 75
percent equities and 25 percent debt. Objectives do not target a
specific return by asset class. The portfolios’ return is monitored
in total. Following is a description of the valuation methodologies
used for trust assets measured at fair value at December 31,
2009.
Mutual
Funds
The fair
values of mutual funds are derived from quoted market prices or net asset values
as these instruments have active markets (Level 1 inputs).
Other
Trust Funds
The
Company’s plans have investments in trust funds similar to mutual funds in that
they are created by pooling of funds from investors into a common trust and such
funds are managed by a third party investment manager. These trust funds
typically give investors a wider range of investment options through this
pooling of funds than that generally available to investors on an individual
basis. However, unlike mutual funds, these trusts are not publicly traded in an
active market. The fair values of these trusts consist of a daily calculated
unit value containing observable (Level 2) market inputs. These funds are
primarily comprised of investments in equity and fixed income securities which
represent approximately 46 percent and 48 percent, respectively, of their fair
value as of December 31, 2009. Equity securities within these funds are
primarily valued using quoted market prices as these instruments have active
markets. From time to time, less liquid equity securities are valued using Level
2 inputs, such as bid prices or a closing price, as determined in good faith by
the investment manager. Fixed income securities are valued at the last available
bid prices quoted by an independent pricing service. When valuations are not
readily available, fixed income securities are valued using primarily other
Level 2 inputs as determined in good faith by the investment
manager.
Guaranteed
Annuity Contract
One of
the Company’s pension plans is party to a group annuity contract with John
Hancock Life Insurance Company. At December 31, 2009, the
estimate of undiscounted funds necessary to satisfy John Hancock’s remaining
obligation was $2.9 million. If funds retained by John Hancock are
not sufficient to satisfy retirement payments due these retirees, the shortfall
must be funded by the Company. The composite investment return, net of manger
fees and other charges for the year ended December 31, 2009 was 5.98
percent. The Company values this illiquid investment using long-term
interest rate and mortality assumptions, among others, and is therefore
considered a Level 3 investment.
The fair
values of the Company’s pension and other retirement plan assets at December 31,
2009 by asset category and by fair value hierarchy are as follows:
|
(In
millions)
|
Level
1
|
Level
2
|
Level
3
|
Total
|
||||||||||||
|
Common
stocks
|
$ | 46.7 | 48.3 | $ | - | $ | 95.0 | |||||||||
|
Fixed
income securities
|
31.1 | 50.4 | - | 81.5 | ||||||||||||
|
International,
real estate, & other
|
28.2 | 6.8 | - | 35.0 | ||||||||||||
|
Guaranteed
annuity contract
|
- | - | 3.6 | 3.6 | ||||||||||||
|
Total
Plan Investments
|
$ | 106.0 | $ | 105.5 | $ | 3.6 | $ | 215.1 | ||||||||
A roll
forward of the fair value of guaranteed annuity contract calculated using Level
3 valuation assumptions follows:
|
(In
millions)
|
2009
|
||
|
Fair
value, beginning of year
|
$ | 3.5 | |
|
Unrealized
gains related to investments
still held at reporting date
|
0.2 | ||
|
Purchases,
sales and settlements, net
|
(0.1 | ) | |
|
Fair
value, end of year
|
$ | 3.6 | |
Funded
Status
The
funded status of the plans as of December 31, 2009 and 2008
follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
(In
millions)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Qualified
Plans
|
||||||||||||||||
|
Benefit obligation,
end of period
|
$ | (256.8 | ) | $ | (246.0 | ) | $ | (79.6 | ) | $ | (72.3 | ) | ||||
|
Fair value of plan
assets, end of period
|
211.1 | 150.9 | 4.0 | 4.3 | ||||||||||||
|
Funded
Status of Qualified Plans, end of period
|
(45.7 | ) | (95.1 | ) | (75.6 | ) | (68.0 | ) | ||||||||
|
Benefit
obligation of SERP Plan, end of period
|
(14.7 | ) | (14.6 | ) | - | - | ||||||||||
|
Total
funded status, end of period
|
$ | (60.4 | ) | $ | (109.7 | ) | $ | (75.6 | ) | $ | (68.0 | ) | ||||
|
Accrued
liabilities
|
$ | 6.0 | $ | 0.7 | $ | 4.5 | $ | 4.3 | ||||||||
|
Other
liabilities
|
$ | 54.4 | $ | 109.0 | $ | 71.1 | $ | 63.7 | ||||||||
-79-
Prior Service Cost,
Actuarial Gains and Losses, and Transition Obligation
Effects
Following
is a roll forward of prior service cost, actuarial gains and losses, and
transition obligations.
|
(In
millions)
|
Pensions
|
Other
Benefits
|
||||||||||||||||||
|
Prior
Service Cost
|
Net
Gain or
Loss
|
Prior
Service Cost
|
Net
Gain or
Loss
|
Transition
Obligation
|
||||||||||||||||
|
Balance
January 1, 2007
|
$ | 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 | |||||||||
|
Amounts
arising during the period
|
0.1 | (20.2 | ) | 0.1 | 6.6 | (0.1 | ) | |||||||||||||
|
Reclassification
to benefit costs
|
(1.7 | ) | (2.2 | ) | 0.8 | (0.4 | ) | (1.1 | ) | |||||||||||
|
Balance
December 31, 2009
|
$ | 7.9 | $ | 68.5 | $ | (2.8 | ) | $ | 9.7 | $ | 5.0 | |||||||||
Due to
moving the measurement date from September 30 to December 31, 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, 2009 and 2008:
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||||||||||||||
|
Pensions
|
Other
Benefits
|
Pensions
|
Other
Benefits
|
Pensions
|
Other
Benefits
|
|||||||||||||||||||
|
Prior
service cost
|
$ | 7.9 | $ | (2.8 | ) | $ | 9.5 | $ | (3.7 | ) | $ | 11.2 | $ | (4.7 | ) | |||||||||
|
Unamortized
actuarial gain/(loss)
|
68.5 | 9.7 | 90.9 | 3.5 | 11.9 | (1.1 | ) | |||||||||||||||||
|
Transition
obligation
|
- | 5.0 | - | 6.2 | - | 7.6 | ||||||||||||||||||
| 76.4 | 11.9 | 100.4 | 6.0 | 23.1 | 1.8 | |||||||||||||||||||
|
Less:
Regulatory asset
deferral
|
(72.6 | ) | (11.3 | ) | (95.4 | ) | (5.7 | ) | (21.9 | ) | (1.7 | ) | ||||||||||||
|
AOCI before
taxes
|
$ | 3.8 | $ | 0.6 | $ | 5.0 | $ | 0.3 | $ | 1.2 | $ | 0.1 | ||||||||||||
Related
to pension plans, $1.6 million of prior service cost and $2.0 million of
actuarial gain/loss is expected to be amortized to cost in
2010. Related to other benefits, $1.1 million of the transition
obligation and $0.5 million of actuarial gain/loss is expected to be amortized
to periodic cost in 2010, and $0.8 million of prior service cost is expected to
reduce cost in 2010.
Expected Cash
Flows
In 2010,
the Company expects to make contributions of approximately $12 million to its
pension plan trusts. In addition, the Company expects to make
payments totaling approximately $6 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 2009 (in millions) are approximately $14 in 2010, $15
in 2011 $16 in 2012, $16 in 2013, $17 in 2014 and $105 in years
2015-2019. Expected benefit payments projected to be required for
postretirement benefits during the years following 2009 (in millions) are
approximately $7 in 2010, $7 in 2011, $8 in 2012, $8 in 2013, and $9 in 2014 and
$53 in years 2015-2019.
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 2009, 2008 and 2007, the Company made
contributions to these plans of $4.6 million, $4.1 million, and $4.0 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,
2009 and 2008, the liability associated with these plans totaled $22.8 million
and $21.1 million, respectively. Other than $6.6 million which is
classified in Accrued
liabilities at December 31, 2009, the liability is included in Deferred credits & other
liabilities. The impact of these plans on Other operating expenses was
expense of $0.8 million in 2009, income of $2.6 million in 2008 and expense of
$2.2 million in 2007.
The
Company has certain investments currently funded primarily through
corporate-owned life insurance policies. These investments, which are
consolidated, are available to pay deferred compensation
benefits. These investments are also subject to the claims of the
Company's creditors. The cash surrender value of these policies
included in Other corporate
& utility investments on the Consolidated Balance Sheets
were $24.7 million and $19.8 million at December 31, 2009 and 2008,
respectively. Earnings from those investments, which are recorded in Other-net, were earnings $4.1
million in 2009, a loss of $2.8 million in 2008, and earnings of $0.6 million in
2007.
|
10.
|
Borrowing
Arrangements
|
Short-Term
Borrowings
At
December 31, 2009, the Company had $775 million of short-term borrowing
capacity, including $520 million for the Utility Group operations and $255
million for the wholly owned Nonutility Group and corporate operations, of which
approximately $462 million was available for the Utility Group operations as
reduced for approximately $41.7 million in outstanding letters of
credit. Approximately $48 million was available for wholly owned
Nonutility Group and corporate operations, as reduced for approximately $9.7
million in outstanding letters of credit. Interest rates and
outstanding balances associated with short-term borrowing arrangements
follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Weighted
average commercial paper and bank loans
|
||||||||||||
|
outstanding
during the year
|
$ | 180.4 | $ | 388.0 | $ | 391.3 | ||||||
|
Weighted
average interest rates during the year
|
||||||||||||
|
Bank
loans
|
0.79 | % | 3.22 | % | 5.61 | % | ||||||
|
Commercial
paper
|
1.29 | % | 3.76 | % | 5.54 | % | ||||||
|
At
December 31,
|
||||||||||||
|
(In
millions)
|
2009 | 2008 | ||||||||||
|
Bank
loans
|
$ | 197.1 | $ | 428.0 | ||||||||
|
Commercial
paper
|
16.4 | 91.5 | ||||||||||
|
Total
short-term borrowings
|
$ | 213.5 | $ | 519.5 | ||||||||
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
provided for revolving loans and letters of credit up to $120 million and was in
addition to Vectren Capital’s $255 million which expires in November
2010. This agreement expired in 2009, was no longer needed, and was
not renewed.
Long-Term
Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
|||||||||||
|
(In
millions)
|
2009
|
2008
|
|||||||||
|
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 | |||||||||
| 2020, 6.28% | 100.0 | - | |||||||||
| 2035, 6.10% | 75.0 | 75.0 | |||||||||
| 2036, 5.95% | 97.8 | 99.1 | |||||||||
| 2039, 6.25% | 122.5 | 124.3 | |||||||||
|
Total
Utility Holdings
|
920.3 | 823.4 | |||||||||
|
SIGECO
|
|||||||||||
|
First Mortgage
Bonds
|
|||||||||||
|
2015,
1985 Pollution Control Series A, current adjustable rate 0.27%, tax
exempt,
|
|||||||||||
|
2009 weighted average: 0.37%
|
9.8 | 9.8 | |||||||||
|
2016, 1986 Series, 8.875%
|
13.0 | 13.0 | |||||||||
|
2020, 1998 Pollution Control Series B, 4.50%, tax exempt
|
4.6 | 4.6 | |||||||||
|
2023, 1993 Environmental Improvement Series B, 5.15%, tax
exempt
|
22.6 | 22.6 | |||||||||
|
2024, 2000 Environmental Improvement Series A, 4.65%, tax
exempt
|
22.5 | 22.5 | |||||||||
|
2025, 1998 Pollution Control Series A, current adjustable rate 0.27%, tax
exempt,
|
|||||||||||
|
2009 weighted average: 0.44%
|
31.5 | 31.5 | |||||||||
|
2029, 1999 Senior Notes, 6.72%
|
80.0 | 80.0 | |||||||||
|
2030, 1998 Pollution Control Series B, 5.00%, tax exempt
|
22.0 | 22.0 | |||||||||
|
2030, 1998 Pollution Control Series C, 5.35%, tax exempt
|
22.2 | 22.2 | |||||||||
|
2040, 2009 Environmental Improvement Series, 5.40%, tax
exempt
|
22.3 | - | |||||||||
|
2041, 2007 Pollution Control Series, 5.45%, tax exempt
|
17.0 | 17.0 | |||||||||
|
Total
SIGECO
|
267.5 | 245.2 | |||||||||
|
Indiana
Gas
|
|||||||||||
|
Fixed Rate 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 | |||||||||
-82-
|
At
December 31,
|
|||||||||||
|
(In
millions)
|
2009
|
2008
|
|||||||||
|
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 | |||||||||
| 2014, 6.37% | 30.0 | - | |||||||||
| 2015, 5.31% | 75.0 | 75.0 | |||||||||
| 2016, 6.92% | 60.0 | - | |||||||||
| 2019, 7.30% | 60.0 | - | |||||||||
|
Total
Vectren Capital Corp.
|
332.5 | 182.5 | |||||||||
|
Other
Long-Term Notes Payable
|
1.2 | 0.7 | |||||||||
|
Total
long-term debt outstanding
|
1,642.5 | 1,372.8 | |||||||||
|
Current maturities of long-term debt
|
(48.0 | ) | (0.4 | ) | |||||||
|
Debt subject to tender
|
(51.3 | ) | (80.0 | ) | |||||||
|
Unamortized debt premium & discount - net
|
(2.7 | ) | (3.2 | ) | |||||||
|
Treasury debt
|
- | (41.3 | ) | ||||||||
|
Total
long-term debt-net
|
$ | 1,540.5 | $ | 1,247.9 | |||||||
Utility
Holdings 2009 Debt Issuance
On April
7, 2009, Utility Holdings entered into a private placement Note Purchase
Agreement pursuant to which institutional investors purchased from Utility
Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020
(2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’
three utilities: SIGECO, Indiana Gas, and VEDO. These
guarantees are full and unconditional and joint and several. The
proceeds from the sale of the 2020 Notes, net of issuance costs, totaled
approximately $99.5 million.
The 2020
Notes have no sinking fund requirements, and interest payments are due
semi-annually. The 2020 Notes contain customary representations,
warranties and covenants, including a leverage covenant consistent with leverage
covenants contained in the Utility Holdings’ $515 million short-term credit
facility.
SIGECO
2009 Debt Issuance
On August
19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond
issuance at an interest rate of 5.4 percent that is fixed through
maturity. The bonds mature in 2040. The proceeds from the
sale of the bonds, net of issuance costs, totaled approximately $21.3
million.
Vectren
Capital Corp. 2009 Debt Issuance
On March
11, 2009, Vectren and Vectren Capital Corp., its wholly-owned subsidiary
(Vectren Capital), entered into a private placement Note Purchase Agreement (the
“2009 Note Purchase Agreement”) pursuant to which various institutional
investors purchased the following tranches of notes from Vectren Capital: (i)
$30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in
6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30
percent senior notes, Series C due 2019. These senior notes are unconditionally
guaranteed by Vectren, the parent of Vectren Capital. These notes
have no sinking fund requirements, and interest payments are due
semi-annually. The proceeds from the sale of the notes, net of
issuance costs, totaled approximately $149.0 million.
The 2009
Note Purchase Agreement contains customary representations, warranties and
covenants, including a leverage covenant consistent with leverage covenants
contained in the Vectren Capital $255 million short-term credit
facility.
On March
11, 2009, Vectren and Vectren Capital also entered into a first amendment with
respect to prior note purchase agreements for the remaining outstanding Vectren
Capital debt, other than the $22.5 million series due in 2010, to conform the
covenants in certain respects to those contained in the 2009 Note Purchase
Agreement.
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 2009 and 2008, the
Company repaid approximately $3.0 million and $1.6 million, respectively,
related to death puts. In 2007, 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 2009 (in millions) is $10.0 in 2010, $30.0 in
2011, zero in 2012 and thereafter. Debt that may be put to the
Company within one year or debt that is supported by lines of credit that expire
within one year are 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.
On March
26, 2009, SIGECO remarketed the remaining $41.3 million of long-term debt held
in treasury at December 31, 2008, receiving proceeds, net of issuance costs of
approximately $40.6 million. The remarketed notes have a variable
rate interest rate which is reset weekly and are supported by a standby letter
of credit backed by Utility Holdings’ $515 million short-term credit
facility. The notes are collateralized by SIGECO’s utility plant, and
$9.8 million are due in 2015 and $31.5 million are due in 2025. The
initial interest rate paid to investors was 0.55 percent. The
equivalent rate of the debt at inception, inclusive of interest, weekly
remarketing fees, and letter of credit fees, approximated 1
percent. Because these notes are supported by Utility Holdings’ short
term credit facility and that facility expires within one year, such debt is
classified as Long-term debt
subject to tender in current liabilities.
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 2010 sinking fund
requirement by this means and, accordingly, the sinking fund requirement for
2010 is excluded from Current
liabilities in the Consolidated Balance
Sheets. At December 31, 2009, $1.2 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 $2.5
billion at December 31, 2009.
Consolidated
maturities of long-term debt during the five years following 2009 (in millions)
are $48.0 in 2010, $250.0 in 2011, $60.0 in 2012, $105.0 in 2013, and $30.0 in
2014.
Debt
Guarantees
Vectren
Corporation guarantees Vectren Capital’s long-term and short-term debt, which
totaled $332 million and $197 million, respectively, at December 31,
2009. 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, 2009, totaled $920 million and $16 million,
respectively.
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, 2009, 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, 2009 and 2008, the Company was authorized to issue 480.0 million
shares of common stock and 20.0 million shares of preferred stock. Of
the authorized common shares, approximately 6.2 million shares at December 31,
2009 and 5.6 million shares at December 31, 2008, 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, 2009,
and 2008, there were 392.7 million and 393.4 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.
|
12.
|
Accumulated
Other Comprehensive Income
|
A summary
of the components of and changes in Accumulated other comprehensive
income for the past three years follows:
|
2007
|
2008
|
2009
|
||||||||||||||||||||||||||
|
Beginning
|
Changes
|
End
|
Changes
|
End
|
Changes
|
End
|
||||||||||||||||||||||
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
||||||||||||||||||||||
|
(In
millions)
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
|||||||||||||||||||||
|
Unconsolidated
affiliates
|
$ | 10.2 | $ | 11.0 | $ | 21.2 | $ | (50.2 | ) | $ | (29.0 | ) | $ | 21.9 | $ | (7.1 | ) | |||||||||||
|
Pension
& other benefit costs
|
(2.5 | ) | 1.2 | (1.3 | ) | (4.0 | ) | (5.3 | ) | 0.9 | (4.4 | ) | ||||||||||||||||
|
Cash
flow hedges
|
0.7 | (0.1 | ) | 0.6 | (0.5 | ) | 0.1 | - | 0.1 | |||||||||||||||||||
|
Deferred
income taxes
|
(3.3 | ) | (4.7 | ) | (8.0 | ) | 21.9 | 13.9 | (9.3 | ) | 4.6 | |||||||||||||||||
|
Accumulated
other comprehensive income (loss)
|
$ | 5.1 | $ | 7.4 | $ | 12.5 | $ | (32.8 | ) | $ | (20.3 | ) | $ | 13.5 | $ | (6.8 | ) | |||||||||||
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 5 for more
information on ProLiance.)
|
13.
|
Earnings
Per Share
|
The FASB
recently clarified that unvested share-based payment awards that contain rights
to nonforfeitable dividends are participating securities subject to the two
class method. As a result of that clarification, the Company began
using the two class method to calculate EPS on January 1, 2009. The
Company has recalculated all prior periods using the two class method to conform
to the current year presentation with immaterial impacts. The two
class method is an earnings allocation formula that treats a participating
security as having rights to earnings that otherwise would have been available
to common shareholders. Under the two-class method, earnings for a
period are allocated between common shareholders and participating security
holders based on their respective rights to receive dividends as if all
undistributed book earnings for the period were distributed. Basic
earnings per share is computed by dividing net income attributable to only the
common shareholders by the weighted-average number of common shares outstanding
for the period. Diluted earnings per share includes the impact of
stock options and other equity based instruments to the extent the effect is
dilutive. The following table illustrates the basic and dilutive earnings per
share calculations for the three years ended December 31, 2009:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions, except per share data)
|
2009
|
2008
|
2007
|
|||||||||
|
Numerator:
|
||||||||||||
|
Numerator
for basic EPS
|
$ | 132.9 | $ | 128.8 | $ | 142.8 | ||||||
|
Add
back earnings attributable to participating securities
|
0.2 | 0.2 | 0.4 | |||||||||
|
Reported
net income (Numerator for Diluted EPS)
|
$ | 133.1 | $ | 129.0 | $ | 143.2 | ||||||
|
Denominator:
|
||||||||||||
|
Weighted
average common shares outstanding (Basic EPS)
|
$ | 80.7 | $ | 78.3 | $ | 75.9 | ||||||
|
Equity
forward contract
|
- | 0.1 | 0.1 | |||||||||
|
Conversion
of share based compensation arrangements
|
0.3 | 0.3 | 0.4 | |||||||||
|
Adjusted
weighted average shares outstanding and
|
||||||||||||
|
assumed
conversions outstanding (Diluted EPS)
|
$ | 81.0 | $ | 78.7 | $ | 76.4 | ||||||
|
Basic
earnings per share
|
$ | 1.65 | $ | 1.65 | $ | 1.89 | ||||||
|
Diluted
earnings per share
|
$ | 1.64 | $ | 1.63 | $ | 1.87 | ||||||
For the
year ended December 31, 2009, options to purchase 837,100 of additional shares
of the Company’s common stock were outstanding, but were not included in the
computation of diluted EPS because their effect would be
antidilutive. The exercise prices for these options ranged from
$23.19 to $27.15 for the year ended December 31, 2009. For the years
ended December 31, 2008 and 2007, all options were dilutive.
|
14.
|
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 Company 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)
|
2009
|
2008
|
2007
|
|||||||||
|
Total
cost of share-based compensation
|
$ | 4.6 | $ | 3.7 | $ | 2.5 | ||||||
|
Less
capitalized cost
|
1.6 | 0.9 | 0.5 | |||||||||
|
Total
in other operating expense
|
3.0 | 2.8 | 2.0 | |||||||||
|
Less
income tax benefit in earnings
|
1.2 | 1.1 | 0.8 | |||||||||
|
After
tax effect of share-based compensation
|
$ | 1.8 | $ | 1.7 | $ | 1.2 | ||||||
Restricted Stock &
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. However, some awards are also time-vested awards that vest
ratably over a four year period. 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. Certain
share awards to key non-officer employees must be settled in shares and are
therefore accounted for in equity at their grant date fair value.
A summary
of the status of the Company’s restricted stock and restricted unit awards
separated between those accounted for as liabilities and equity as of December
31, 2009, and changes during the year ended December 31, 2009,
follows:
|
Equity
Awards
|
||||||||||||||||
|
Wtd.
Avg.
|
||||||||||||||||
|
Grant
Date
|
Liability
Awards
|
|||||||||||||||
|
Shares
|
Fair
value
|
Shares/Units
|
Fair
value
|
|||||||||||||
|
Restricted
at January 1, 2009
|
36,235 | $ | 28.24 | 524,393 | ||||||||||||
|
Granted
|
12,370 | $ | 24.76 | 269,429 | ||||||||||||
|
Vested
|
(6,761 | ) | $ | 26.65 | (129,937 | ) | ||||||||||
|
Forfeited
|
(2,931 | ) | $ | 27.73 | (57,532 | ) | ||||||||||
|
Restricted
at December 31, 2009
|
38,913 | $ | 27.55 | 606,353 | $ | 24.68 | ||||||||||
As of December 31, 2009, there was $6.5 million of total unrecognized compensation cost related to restricted stock awards. That cost is expected to be recognized over a weighted-average period of 2.7 years. The total fair value of shares vested for liability awards during the years ended December 31, 2009, 2008, and 2007, was $2.8 million, $0.4 million, and $1.9 million, respectively. The total fair value of equity awards vesting during the year ended December 31, 2009 and 2007 was $0.1 million and $0.1 million, respectively. No equity awards vested in 2008.
On
February 10, 2010, the Company issued 270,810 restricted units to executives and
other key non-officer employees. These awards were primarily in the
form of restricted units, and contained primarily performance based
provisions. Some awards, however, contain only time based vesting
provisions. Most awards can only be settled in
cash. Dividends on performance based awards 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. In addition,
on February 10, 2010, participants forfeited 24,333 shares related to awards
measured during the three year performance period ending December 31,
2009.
-87-
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, 2009, and
changes during the year ended December 31, 2009, follows:
|
Weighted
average
|
Aggregate
|
|||||||||||||||
|
Remaining
|
Intrinsic
|
|||||||||||||||
|
Shares
|
Exercise
|
Contractual
|
Value
|
|||||||||||||
|
Price
|
Term
(years)
|
(In
millions)
|
||||||||||||||
|
Outstanding
at January 1, 2009
|
1,335,214 | $ | 23.95 | |||||||||||||
|
Exercised
|
(5,652 | ) | $ | 20.26 | ||||||||||||
|
Outstanding
at December 31, 2009
|
1,329,562 | $ | 23.97 | 3.0 | $ | 1.5 | ||||||||||
|
Exercisable
at December 31, 2009
|
1,329,562 | $ | 23.97 | 3.0 | $ | 1.5 | ||||||||||
The total intrinsic value of options exercised during the year ended December 31, 2008 and 2007 was $0.5 million, and $3.6 million, respectively. As of December 31, 2009, all compensation cost has been recognized. The actual tax benefit realized for tax deductions from option exercises was approximately $0.1 million in 2008 and $1.2 million in 2007.
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 and 2007, the Company received cash upon exercise of stock
options totaling approximately $1.9 million and $11.4 million,
respectively. During those periods, the Company repurchased shares
totaling approximately $2.2 million in 2008 and $6.9 million in
2007. During the year ended December 31, 2009, stock option activity
was insignificant.
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, 2009, 2008, and 2007, was a
benefit of $1.5 million, a cost of $0.6 million and a cost of $0.4 million,
respectively.
|
15.
|
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 2009 and thereafter (in millions) are $4.5 in 2010, $2.6 in 2011, $1.4
in 2012, $0.8 in 2013, $0.7 in 2014, and $0.3 thereafter. Total lease
expense (in millions) was $8.0 in 2009, $8.8 in 2008, and $8.7 in
2007.
Firm nonutility purchase commitments
for commodities by consolidated companies total (in millions) $4.9 in 2010, $3.8
in 2011, $8.2 in 2012, $8.4 in 2013, and $8.6 in 2014.
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase natural gas, electricity, and coal 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.
Corporate
Guarantees
The
Company issues corporate guarantees to certain vendors and customers of its
wholly owned subsidiaries and unconsolidated affiliates. These
guarantees do not represent incremental consolidated obligations; rather, they
represent parental guarantees of subsidiary and unconsolidated affiliate
obligations in order to allow those subsidiaries and affiliates the flexibility
to conduct business without posting other forms of collateral. At
December 31, 2009, corporate issued guarantees support a portion of ESG’s
performance contracting commitments and warranty obligations described
below. In addition, the Company has approximately $60 million of
other guarantees outstanding supporting other consolidated subsidiary
operations, of which $46 million support non-regulated retail gas supply
operations. Guarantees issued and outstanding on behalf of
unconsolidated affiliates approximated $3 million at December 31,
2009. These guarantees relate primarily to arrangements between
ProLiance and various natural gas pipeline operators. The Company has
not been called upon to satisfy any obligations pursuant to these parental
guarantees and has accrued no significant liabilities related to these
guarantees.
Performance
Guarantees & Product Warranties
In the
normal course of business, ESG and other wholly owned subsidiaries issue
performance bonds or other forms of assurance that commit them to timely install
infrastructure, operate facilities, pay vendors or subcontractors, and/or
support warranty obligations. Based on a history of meeting
performance obligations and installed products operating effectively, no
significant liability or cost has been recognized for the periods
presented.
Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2009, there are 54 open surety bonds supporting future performance. The average face amount of these obligations is $3.6 million, and the largest obligation has a face amount of $30.4 million. These surety bonds are guaranteed by Vectren Corporation. The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed. At December 31, 2009, over 50 percent of work was completed on projects with open surety bonds. A significant portion of these commitments will be fulfilled within one year. In instances where ESG operates facilities, project guarantees extend over a longer period.
In
addition to its performance obligations, ESG also warrants the functionality of
certain installed infrastructure generally for one year and the associated
energy savings over a specified number of years. In certain
instances, these warranty obligations are also backed by Vectren
Corporation.
Legal & Regulatory
Proceedings
The
Company is party to various legal proceedings, audits, and reviews by taxing
authorities and other government agencies arising in the normal course of
business. In the opinion of management, there are no legal
proceedings or other regulatory reviews or audits pending against the Company
that are likely to have a material adverse effect on its financial position,
results of operations or cash flows.
|
16.
|
Environmental
Matters
|
Clean Air
Act
The Clean
Air Interstate Rule (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 and
is positioned to comply with SO2 reductions
effective January 1, 2010. Utilization of the Company’s inventory of
NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of 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. In response to the court decision, USEPA has announced
that it intends to publish proposed Maximum Achievable Control Technology
standards for mercury in 2010. It is uncertain what emission limit
the USEPA is considering, and whether they will address hazardous pollutants in
addition to mercury. It is also possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress.
-89-
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. The Company
has invested approximately $100 million in this project. The scrubber
was placed into service on January 1, 2009. 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
The U.S.
House of Representatives has passed a comprehensive energy bill that includes a
carbon cap and trade program in which there is a progressive cap on greenhouse
gas emissions and an auctioning and subsequent trading of allowances among those
that emit greenhouse gases, a federal renewable portfolio standard, and utility
energy efficiency targets. Current proposed legislation also requires
local natural gas distribution companies to hold allowances for the benefit of
their customers. As of the date of this filing, the Senate has not
passed a bill, and the House bill is not law. The U.S. Senate is
currently debating a cap and trade proposal that is similar in structure to the
House bill.
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 Indiana,
the state is an observer to the Midwestern Regional Greenhouse Gas Reduction
Accord, and in its completed 2009 session, the state’s legislature debated, but
did not pass, a renewable energy portfolio standard.
In
advance of a federal or state renewable portfolio standard, SIGECO received
regulatory approval to purchase a 3 MW landfill gas generation facility from a
related entity. The facility was purchased in 2009 and is directly
interconnected to the Company’s distribution system. In 2009, the
Company also executed a long term purchase power commitment for 50 MW of wind
energy. These transactions supplement a 30 MW wind energy purchase
power agreement executed in 2008.
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 motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. In April of 2009, the USEPA published its proposed
endangerment finding for public comment. The proposed endangerment
finding concludes that carbon emissions from mobile sources pose an endangerment
to public health and the environment. The endangerment finding was
finalized in December of 2009, and is the first step toward USEPA regulating
carbon emissions through the existing Clean Air Act in the absence of specific
carbon legislation from Congress. Therefore, any new regulations
would likely also impact major stationary sources of greenhouse
gases. The USEPA has recently finalized a mandatory greenhouse gas
emissions registry which will require reporting of emissions beginning in 2011
(for the emission year 2010). The USEPA has also recently proposed a
revision to the PSD (Prevention of Significant Deterioration) and Title V
permitting rules which would require facilities that emit 25,000 tons or more of
greenhouse gases a year to obtain a PSD permit for new construction or a
significant modification of an existing facility. If these proposed
rules were adopted, they would apply to SIGECO’s generating
facilities.
Impact
of Legislative Actions & 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 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 with regard operating expenses for the purchase of
allowances, and later for capital expenditures as technology becomes available
to control greenhouse gas emissions. However, these compliance cost
estimates are based on highly uncertain assumptions, including allowance prices
and energy efficiency targets. 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 20 percent of electric volumes
sold in 2008 were delivered to municipal and other wholesale
customers. As such, reductions in these volumes in 2009 coupled with
the flexibility to further modify the level of these transactions in future
periods may help with compliance if emission targets are based on pre-2008
levels.
Ash Ponds & Coal
Ash Disposal Regulations
The USEPA
is considering additional regulatory measures affecting the management and
disposal of coal combustion products, such as ash generated by the Company’s
coal-fired power plants. Additional laws and regulations under
consideration more stringently regulate these byproducts, including the
potential for coal ash to be considered a hazardous waste in certain
circumstances. The USEPA has indicated that it intends to propose a rule
during 2010. At this time, the Company is unable to predict the
outcome any such revised regulations might have on operating results, financial
position, or liquidity.
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. Vectren's own soil testing, completed during the
construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils above industrial cleanup
levels. At this time, it is anticipated that the USEPA may request
only additional soil testing at some future date.
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 $23.2
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 limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50
percent.
With
respect to insurance coverage, Indiana Gas has settled with all known insurance
carriers under insurance policies in effect when these plants were in operation
in an aggregate amount approximating $20.8 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 waste
disposal site subject to potential environmental remediation
efforts. With respect to that lawsuit, in an October 2009 court
decision, SIGECO was found to be a PRP at the site. However, the
Court must still determine whether such costs should be allocated among a number
of PRPs, including the former owners of the site. 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.
SIGECO
has recorded cumulative costs that it reasonably expects to incur related to
these environmental matters totaling approximately $11.1
million. However, given the uncertainty surrounding the allocation of
PRP responsibility associated with the May 2007 lawsuit and other matters, the
total costs that may be incurred in connection with addressing all of these
sites cannot be determined at this time. With respect to insurance
coverage, SIGECO has settled with certain of its known insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.1 million; negotiations are ongoing with others. SIGECO
has undertaken significant remediation efforts at two MGP sites.
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, 2009 and December 31, 2008,
approximately $6.5 million of accrued, but not yet spent, remediation costs are
included in Other Liabilities
related to both the Indiana Gas and SIGECO sites.
|
17.
|
Rate
& Regulatory Matters
|
Vectren South Electric Base
Rate Filings
On
December 11, 2009, the Company filed a request with the IURC to adjust its
electric base rates in its South service territory. The requested
increase in base rates addresses capital investments, a modified electric rate
design that facilitates a partnership between the Company and customers to
pursue energy efficiency and conservation, and new energy efficiency programs to
complement those currently offered for natural gas customers. In
total the request approximated $54 million. The request addresses the
roughly $325 million spent in infrastructure construction since its last base
rate increase in August 2007 that was needed to continue to provide reliable
service. Most of the remainder of the request is to account for the
now lower overall sales levels resulting from the recession. A
portion of the request reflects a slight increase in annual operating and
maintenance costs since the last rate case, nearly four years
ago. The rate design proposed in the filing would break the link
between customers’ consumption and the utility’s rate of return, thereby
aligning the utility’s and customers’ interests in using less
energy. The request assumes an overall rate of return of 7.62 percent
on rate base of approximately $1,294 million and an allowed return on equity
(ROE) of 10.7 percent. Based upon timelines prescribed by the IURC at
the start of these proceedings, a decision is expected to be issued at the end
of 2010.
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 adjusted the rate design used to collect the agreed-upon revenue from
VEDO's customers. The order allows for the phased movement toward a
straight fixed variable rate design which places substantially all of the fixed
cost recovery in the customer service charge. A straight fixed
variable design mitigates most 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 on February 22, 2009. In
2008, annual results include approximately $4.3 million of revenue from a lost
margin recovery mechanism that did not continue once this base rate increase
went into effect. After year one, nearly 90 percent of the combined
residential and commercial base rate margins were recovered through the customer
service charge. 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. The Ohio Supreme Court has yet to act on the OCC’s request
in this instance, but in two similar cases, the Court denied such
requests.
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 uncollectible accounts
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. The straight fixed variable rate
design will be fully phased in by February 2010.
VEDO Continues the 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 eliminated the need
for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits. On October 1, 2008, VEDO’s entire natural gas inventory was
transferred, receiving proceeds of approximately $107 million.
The
second phase of the exit process begins on April 1, 2010, during which the
Company will no longer sell natural gas directly to these
customers. Rather, state-certified Competitive Retail Natural Gas
Suppliers, that are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers for 12 months at
auction-determined standard pricing. That auction was conducted on
January 12, 2010, and the auction results were approved by the PUCO on January
13. The plan approved by the PUCO requires that the Company conduct at
least two auctions during this phase. As such, the Company will conduct
another auction in advance of the second 12-month term, which will commence on
April 1, 2011. Consistent with current practice, customers will
continue to receive one bill for the delivery of natural gas
service.
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 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 uncollectible accounts 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 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 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 uncollectible accounts 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
In August
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.
MISO
Since
2002 and with the IURC’s approval, the Company has been a member of the 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.
MISO-related
purchase and sale transactions are recorded using settlement information
provided by MISO. These purchase and sale transactions are accounted for on a
net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power
and net sales in a single hour are recorded in Electric utility revenues. On
occasion, prior period transactions are resettled outside the routine process
due to a change in MISO’s tariff or a material interpretation
thereof. Expenses associated with resettlements are recorded once the
resettlement is probable and the resettlement amount can be estimated. Revenues
associated with resettlements are recognized when the amount is determinable and
collectability is reasonably assured.
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. The Company also has municipal customers served
through the MISO and for which the Company transmits power to the MISO for
delivery to those customers. Net revenues from wholesale activities,
inclusive of revenues associated with these municipal contracts, totaled $20.8
million in 2009, $57.6 million in 2008, and $35.0 million in 2007 and are
recorded in Electric utility
revenues. The base rate case effective August 17, 2007,
requires that wholesale margin (net revenues less the cost of fuel and purchased
power) inclusive of this MISO wholesale activity earned above or below $10.5
million be shared equally with retail customers as measured on a fiscal year
ending in August.
Recently,
MISO market prices have fallen and the Company has more frequently been a net
purchaser. In addition, the Company also receives power through the
MISO associated with its wind and other power purchase
agreements. Including these power purchase agreements, the Company
purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in
2008, and $18.2 million in 2007. To the extent these power purchases
are used for retail load, they are included in FAC filings.
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 from / refunded to retail
customers 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 recover costs associated with ASM. To
date impacts from the ASM have been minor.
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. Beginning in
June 2008, the Company began timely recovering its investment in certain new
electric transmission projects that benefit the MISO infrastructure at a FERC
approved rate of return. Such revenues recorded in Electric utility revenues
associated with projects meeting the criteria of MISO’s transmission
expansion plans totaled $9.1 million in 2009 and $4.8 million in
2008.
|
18.
|
Fair
Value Measurements
|
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
||||||||||||||||
|
2009
|
2008
|
|||||||||||||||
|
(In
millions)
|
Carrying
Amount
|
Est.
Fair
Value
|
Carrying
Amount
|
Est.
Fair
Value
|
||||||||||||
|
Long-term
debt
|
$ | 1,642.5 | $ | 1,720.1 | $ | 1,372.8 | $ | 1,251.0 | ||||||||
|
Short-term
borrowings & notes payable
|
213.5 | 213.5 | 519.5 | 519.5 | ||||||||||||
|
Cash
& cash equivalents
|
11.9 | 11.9 | 93.2 | 93.2 | ||||||||||||
For the balance sheet dates presented in these financial statements, other than $75 million invested in money market funds and included in Cash and cash equivalents as of December 31, 2008, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs. The money market investments were valued using Level 1 inputs.
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 and cash & cash equivalents, those carrying
amounts approximate fair value. Because of the inherent difficulty of
estimating interest rate and other market risks, the methods used to estimate
fair value may not always be indicative of actual realizable value, and
different methodologies could produce different fair value estimates at the
reporting date.
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
cost. At December 31, 2009 and 2008, the fair value for these
financial instruments was not estimated. The carrying value of notes
receivable, inclusive of any accrued interest and net of impairment reserves,
was approximately $16.7 million at both December 31, 2009 and 2008.
|
19.
|
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)
|
2009
1/
|
2008
|
2007
|
|||||||||
|
Revenues
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Electric
Utility Services
|
528.6 | 524.2 | 487.9 | |||||||||
|
Other
Operations
|
42.8 | 36.8 | 40.4 | |||||||||
|
Eliminations
|
(41.2 | ) | (35.0 | ) | (38.7 | ) | ||||||
|
Total
Utility Group
|
1,596.2 | 1,958.7 | 1,759.0 | |||||||||
|
Nonutility
Group
|
673.9 | 664.7 | 643.4 | |||||||||
|
Eliminations
|
(181.2 | ) | (138.7 | ) | (120.5 | ) | ||||||
|
Consolidated
Revenues
|
$ | 2,088.9 | $ | 2,484.7 | $ | 2,281.9 | ||||||
|
Profitability
Measures - Net Income
|
||||||||||||
|
Gas
Utility Services
|
$ | 50.2 | $ | 53.3 | $ | 41.7 | ||||||
|
Electric
Utility Services
|
48.3 | 50.7 | 52.6 | |||||||||
|
Other
Operations
|
8.9 | 7.1 | 12.2 | |||||||||
|
Utility
Group Net Income
|
107.4 | 111.1 | 106.5 | |||||||||
|
Nonutility
Group Net Income
|
25.8 | 18.9 | 37.0 | |||||||||
|
Corporate
& Other Net Loss
|
(0.1 | ) | (1.0 | ) | (0.4 | ) | ||||||
|
Consolidated
Net Income
|
$ | 133.1 | $ | 129.0 | $ | 143.1 | ||||||
1/ Net
income during the year ended December 31, 2009 includes the impact of a charge
discussed in Note 5 in the Company’s Consolidated Financial Statements totaling
$11.9 million after tax related to ProLiance’s investment in Liberty Gas
Storage. Excluding this charge, there was Nonutility Group Net Income
of $37.7 million and Consolidated Net Income of $145.0 million.
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Amounts
Included in Profitability Measures
|
||||||||||||
|
Depreciation & Amortization
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 76.9 | $ | 74.1 | $ | 70.6 | ||||||
|
Electric
Utility Services
|
77.5 | 68.5 | 66.0 | |||||||||
|
Other
Operations
|
26.5 | 22.9 | 21.8 | |||||||||
|
Total
Utility Group
|
180.9 | 165.5 | 158.4 | |||||||||
|
Nonutility
Group
|
31.0 | 26.8 | 26.4 | |||||||||
|
Consolidated
Depreciation & Amortization
|
$ | 211.9 | $ | 192.3 | $ | 184.8 | ||||||
|
Interest Expense
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 38.8 | $ | 42.0 | $ | 39.8 | ||||||
|
Electric
Utility Services
|
34.8 | 32.0 | 29.6 | |||||||||
|
Other
Operations
|
5.6 | 5.9 | 11.2 | |||||||||
|
Total
Utility Group
|
79.2 | 79.9 | 80.6 | |||||||||
|
Nonutility
Group
|
20.9 | 17.3 | 21.9 | |||||||||
|
Corporate
& Other
|
(0.1 | ) | 0.6 | (1.5 | ) | |||||||
|
Consolidated
Interest Expense
|
$ | 100.0 | $ | 97.8 | $ | 101.0 | ||||||
|
Income Taxes
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas
Utility Services
|
$ | 31.3 | $ | 35.5 | $ | 33.2 | ||||||
|
Electric
Utility Services
|
27.4 | 32.0 | 38.0 | |||||||||
|
Other
Operations
|
0.5 | 0.1 | (4.5 | ) | ||||||||
|
Total
Utility Group
|
59.2 | 67.6 | 66.7 | |||||||||
|
Nonutility
Group
|
5.9 | 9.5 | 10.5 | |||||||||
|
Corporate
& Other
|
(1.0 | ) | (1.0 | ) | (1.2 | ) | ||||||
|
Consolidated
Income Taxes
|
$ | 64.1 | $ | 76.1 | $ | 76.0 | ||||||
|
Capital Expenditures
|
||||||||||||
|
Utility
Group
|
||||||||||||
|
Gas Utility
Services
|
$ | 121.1 | $ | 110.4 | $ | 128.9 | ||||||
|
Electric Utility
Services
|
154.1 | 172.0 | 134.7 | |||||||||
|
Other
Operations
|
16.7 | 29.6 | 36.4 | |||||||||
|
Non-cash costs
& changes in accruals
|
10.8 | (8.3 | ) | (0.2 | ) | |||||||
|
Total
Utility Group
|
302.7 | 303.7 | 299.8 | |||||||||
|
Nonutility
Group
|
129.3 | 87.3 | 34.7 | |||||||||
|
Consolidated
Capital Expenditures
|
$ | 432.0 | $ | 391.0 | $ | 334.5 | ||||||
-97-
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Assets
|
||||||||
|
Utility
Group
|
||||||||
|
Gas Utility
Services
|
$ | 2,102.4 | $ | 2,204.7 | ||||
|
Electric Utility
Services
|
1,592.4 | 1,462.1 | ||||||
|
Other Operations,
net of eliminations
|
128.3 | 171.3 | ||||||
|
Total Utility
Group
|
3,823.1 | 3,838.1 | ||||||
|
Nonutility
Group
|
836.0 | 780.1 | ||||||
|
Corporate &
Other
|
715.9 | 737.5 | ||||||
|
Eliminations
|
(703.2 | ) | (722.8 | ) | ||||
|
Consolidated
Assets
|
$ | 4,671.8 | $ | 4,632.9 | ||||
|
20.
|
Synfuel-Related
Activity
|
Tax laws
authorizing synfuel credits expired on December 31, 2007. Prior to
that date, the Company had active synthetic fuel investments, including an
investment in Pace Carbon Synfuels, LP. The Company accounts for its
8.3 percent ownership interest in Pace Carbon using the equity
method. Activity since December 31, 2007 has been insignificant and
is generally focused on winding down partnership operations.
Generally, the statute of limitations
for the IRS to audit a tax return is three years from filing. Therefore
tax credits utilized in 2006 – 2007 are still subject to IRS examination.
However, avenues remain where the IRS could challenge tax credits for the years
prior to 2006. As a partner of Pace Carbon, Vectren reflected
cumulative synfuel tax credits of approximately $101 million in its consolidated
results, of which approximately $22 million were generated in 2006 and
2007. Vectren has utilized 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 IRC, 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. The Company executed several financial contracts to hedge
oil price risk. Income statement activity associated with these
contracts was a gain of $13.4 million in 2007. This activity is
reflected in Other-net
along with the effects of impairing the Pace Carbon investment in 2006 in
advance of equity method losses experienced in 2007. Synfuel-related
results, inclusive of equity method losses in Pace Carbon, related tax benefits
and tax credits, and other related activity, were earnings of $6.8 million in
2007.
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.
|
21.
|
Additional
Balance Sheet & Operational
Information
|
Prepayments & other current
assets in the Consolidated Balance Sheets
consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Prepaid
gas delivery service
|
$ | 38.7 | $ | 75.0 | ||||
|
Deferred
income taxes
|
21.7 | 8.2 | ||||||
|
Prepaid
taxes
|
20.6 | 14.1 | ||||||
|
Other
prepayments & current assets
|
14.1 | 27.3 | ||||||
|
Total
prepayments & other current assets
|
$ | 95.1 | $ | 124.6 | ||||
Other utility & corporate
Investments in the Consolidated Balance Sheets
consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Cash
surrender value of life insurance policies
|
$ | 24.7 | $ | 19.8 | ||||
|
Municipal
bond
|
4.3 | 4.5 | ||||||
|
Restricted
cash
|
2.8 | - | ||||||
|
Other
investments
|
1.4 | 1.4 | ||||||
|
Other
utility & corporate investments
|
$ | 33.2 | $ | 25.7 | ||||
Accrued liabilities in the
Consolidated Balance
Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Refunds
to customers & customer deposits
|
$ | 51.0 | $ | 45.5 | ||||
|
Accrued
taxes
|
32.7 | 46.3 | ||||||
|
Accrued
interest
|
23.7 | 19.2 | ||||||
|
Asset
retirement obligation
|
3.0 | 7.2 | ||||||
|
Accrued
retirement & deferred compensation benefits
|
19.6 | 5.0 | ||||||
|
Accrued
salaries & other
|
44.7 | 51.8 | ||||||
|
Total
accrued liabilities
|
$ | 174.7 | $ | 175.0 | ||||
Other – net in the Consolidated Statements of
Income consists of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
AFUDC
– borrowed funds
|
$ | 1.3 | $ | 2.2 | $ | 3.5 | ||||||
|
AFUDC
– equity funds
|
0.7 | 0.3 | 0.5 | |||||||||
|
Nonutility
plant capitalized interest
|
6.0 | 3.7 | 2.3 | |||||||||
|
Interest
income, net
|
1.4 | 2.3 | 2.9 | |||||||||
|
Synfuel-related
activity
|
- | - | 23.4 | |||||||||
|
Commercial
real estate impairment charge
|
- | (5.2 | ) | - | ||||||||
|
Cash
surrender value of life insurance policies
|
4.1 | (2.8 | ) | 0.6 | ||||||||
|
All
other income
|
0.2 | 1.6 | 3.5 | |||||||||
|
Total
other – net
|
$ | 13.7 | $ | 2.1 | $ | 36.7 | ||||||
|
Year
Ended December 31,
|
|||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
||||
|
Cash
paid for:
|
|||||||
|
Interest
|
95.5
|
92.6
|
97.3
|
||||
|
Income
taxes
|
(12.2)
|
(3.5)
|
43.7
|
||||
As of
December 31, 2009 and 2008, the Company has accruals related to utility and
nonutility plant purchases totaling approximately $12.4 million and $35.5
million, respectively.
|
22.
|
Impact
of Recently Issued Accounting
Guidance
|
Variable Interest
Entities
In June
2009, the FASB issued new accounting guidance regarding variable interest
entities (VIE’s). This new guidance is effective for annual reporting
periods beginning after November 15, 2009. This guidance requires a
qualitative analysis of which holder of a variable interest controls the VIE and
if that interest holder must consolidate a VIE. Additionally, it
requires additional disclosures and an ongoing reassessment of who must
consolidate a VIE. The Company adopted this guidance on January 1,
2010. The Company does not expect the adoption will have a material impact on
the consolidated financial statements.
Fair Value
Measurements & Disclosures
In
January 2010, the FASB issued new accounting guidance on improving disclosures
about fair market value. This guidance amends prior disclosure
requirements involving fair value measurements to add new requirements for
disclosures about transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances, and settlements relating to Level
3 measurements. The guidance also clarifies existing fair value disclosures in
regard to the level of disaggregation and about inputs and valuation techniques
used to measure fair value. The guidance also amends prior disclosure
requirements regarding postretirement benefit plan assets to require that
disclosures be provided by classes of assets instead of major categories of
assets. This guidance is effective for the first reporting period
beginning after December 15, 2009. The Company will adopt this
guidance in its first quarter 2010 reporting. The Company does not
expect the adoption will have a material impact on the consolidated financial
statements.
|
23.
|
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 2009 and 2008
follows:
|
(In
millions, except per share amounts)
|
Q1 | Q2 1/ | Q3 | Q4 | ||||||||||||
|
2009
|
||||||||||||||||
|
Operating
revenues
|
$ | 795.2 | $ | 375.5 | $ | 349.6 | $ | 568.6 | ||||||||
|
Operating
income
|
121.8 | 32.4 | 40.5 | 85.4 | ||||||||||||
|
Net
income
|
72.8 | (6.7 | ) | 12.4 | 54.6 | |||||||||||
|
Earnings
per share:
|
||||||||||||||||
|
Basic
|
$ | 0.90 | $ | (0.08 | ) | $ | 0.15 | $ | 0.68 | |||||||
|
Diluted
|
0.90 | (0.08 | ) | 0.15 | 0.67 | |||||||||||
|
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 | ||||||||||||
1/ The second quarter of 2009 excludes the impact of a charge discussed in Note 5 in the Company’s Consolidated Financial Statements totaling $11.9 million after tax, or $0.15 per share, related to ProLiance’s investment in Liberty Gas Storage. Including this charge, there was consolidated net income of $5.2 million, or $0.07 per share in the second quarter of 2009.
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, 2009, 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, 2009, 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,
2009, 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, 2009.
The
effectiveness of internal control over financial reporting as of December 31,
2009, 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 2010 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.
Management
Succession
Niel C.
Ellerbrook, chairman and CEO of the Company, will retire May 31, 2010, as the
Company’s CEO, after a decade of service in the position. Ellerbrook will serve
in the role of non-executive chairman for the Company.
Ellerbrook
joined Indiana Gas Company, Inc., in 1980 where he assumed increasing
responsibilities culminating in 1999 with his election as president and CEO of
Indiana Energy, Inc., the holding company of Indiana Gas and a predecessor of
Vectren. The Vectren board of directors elected Ellerbrook as chairman and chief
executive officer effective upon its formation in March
2000. Ellerbrook was instrumental in merging two energy holding
companies together to create Vectren while concurrently purchasing the natural
gas distribution assets of Dayton Power and Light. These transactions
have produced one of Indiana’s largest publicly traded corporations. Vectren
provides products and services in nearly half of the United States, including
1.1 million utility customers in Indiana and Ohio.
As part
of the Company’s succession planning process, the board of directors chose Carl
L. Chapman, Vectren’s president and chief operating officer, to replace
Ellerbrook as the next CEO. Chapman was elected to the board of directors in May
2009 and has served as an officer of the company for more than 20
years.
Chapman
joined Indiana Gas Company, Inc., in 1985 after eight years of service with
Arthur Andersen & Co. Chapman has held various executive
management roles including executive vice president and COO of Vectren,
president of Vectren Enterprises, Vectren’s holding company for its nonregulated
subsidiaries and affiliates, and executive vice president and chief financial
officer of Indiana Energy, Inc. He was also instrumental in forming
ProLiance Energy, the company’s largest nonutility affiliate, where he served as
the first president.
Corporate Code of
Conduct
The
Company’s Corporate Governance Guidelines, its charters for each of its Audit,
Compensation and Benefits and Nominating and Corporate Governance Committees,
and its Corporate Code of Conduct that covers the Company’s directors, officers
and employees are available in the Corporate Governance section of the Company’s
website, www.vectren.com. The
Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific
codes of ethics pertaining to the CEO and senior financial officers and the
Board of Directors in Exhibits D and E, respectively. 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 Corporate Code of Conduct or waivers of the Corporate Code
of Conduct on behalf of the Company’s directors or officers including, but not
limited to, the principal executive officer, principal financial officer,
principal accounting officer 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 2010 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 2010 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, 2009, 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
|
1,329,562
|
(1)
|
$ 23.97
|
(1)
|
2,286,193
|
(2)
|
|||
|
Equity
compensation plans not approved
|
|||||||||
|
by security holders
|
-
|
-
|
-
|
||||||
|
Total
|
1,329,562
|
$ 23.97
|
2,286,193
|
||||||
|
(1)
|
Includes
the following Vectren Corporation Plans: Vectren Corporation
At-Risk Compensation 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 270,810 restricted units
approved by the board of directors’ Compensation Committee on February 10,
2010. In addition, on February 10, 2010, participants forfeited
24,333 shares related to awards measured during the three year performance
period ending December 31, 2009, and shares available for future issue
have been increased by that amount. The issuance and forfeiture
of the shares on February 10, 2010 are included in the above
table.
|
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 2010 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 2010 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, 2009, 2008, and 2007, 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
2009 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 5.6 | $ | 15.1 | $ | - | $ | 15.5 | $ | 5.2 | ||||||||||
|
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
2009 – Reserve for impaired
|
||||||||||||||||||||
|
notes
receivable
|
$ | 6.3 | $ | 2.9 | $ | - | $ | - | $ | 9.2 | ||||||||||
|
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 | ||||||||||
|
OTHER
RESERVES:
|
||||||||||||||||||||
|
Year
2009 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | 0.1 | $ | 0.5 | ||||||||||
|
Year
2008 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | - | $ | 0.6 | ||||||||||
|
Year
2007 – Restructuring costs
|
$ | 1.7 | $ | - | $ | - | $ | 1.1 | $ | 0.6 | ||||||||||
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.
Vectren
Corporation
Form
10-K
Attached
Exhibits
The
following Exhibits are included in this Annual Report on Form 10-K.
|
Exhibit
Number
|
Document
|
|
31.1
|
Chief
Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Chief
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
32
|
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
The
following Exhibits, as well as the Exhibits listed above, were filed
electronically with the SEC with this filing.
|
Exhibit
Number
|
Document
|
|
4.1
|
SIGECO
Mortgage Indenture Amendment
|
|
10.1
|
Coal
Supply Agreement Amendment
|
|
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 June 24, 2009. (Filed and designated in Current Report on
Form 8-K filed June 26, 2009, File No. 1-15467, as Exhibit
3.1.)
|
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) August
1, 2009 (Filed herewith, as Exhibit
4.1)
|
|
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.) First Amendment, dated March 11, 2009, to Note Purchase
Agreement dated October 11, 2005, among Vectren Corporation, Vectren
Capital, Corp. and each of the holders named herein. (Filed and designated
in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit
4.6)
|
|
4.5
|
Note
Purchase Agreement, dated March 11, 2009, among Vectren Corporation,
Vectren Capital, Corp. and each of the purchasers named therein. (Filed
and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as
Exhibit 4.5)
|
|
4.6
|
Note
Purchase Agreement, dated April 7, 2009, among Vectren Utility Holdings,
Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company
and Vectren Energy Delivery of Ohio, Inc. and the purchasers named
therein. (Filed and designated in Form 8-K dated April 7, 2009 File No.
1-15467, as Exhibit 4.5)
|
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, 2010. (Filed and designated in
Form 8-K, dated January 7, 2010, File No. 1-15467, as Exhibit
10.1.)
|
|
10.11
|
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.)
|
|
10.12
|
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.)
|
|
10.13
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock units
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.2.)
|
|
10.14
|
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.)
|
|
10.15
|
Vectren
Corporation At Risk Compensation Plan stock unit award agreement for
non-employee directors, effective May 1, 2009. (Filed and designation in
Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit
10.1)
|
|
10.16
|
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.
|
|
10.17
|
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.)
|
|
10.18
|
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.)
|
|
10.19
|
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.)
|
|
10.20
|
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.)
|
|
10.21
|
Amendment
to F.B. Culley and A.B. Brown Coal Supply Agreements dated December 21,
2009. (Filed herewith as exhibit
10.1)
|
|
10.22
|
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.)
|
|
10.23
|
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.)
|
|
10.24
|
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.)
|
|
10.25
|
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-Q, for the period
ended September 30, 2009, File No. 1-15467, as Exhibit
10.24.)
|
|
10.26
|
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-Q, for the period ended September 30, 2009, File
No. 1-15467, as Exhibit 10.25.)
|
|
10.27
|
Niel
C. Ellerbrook Retirement Agreement, dated February 3,
2010. (Filed and
designated in Form 8-K dated February 4, 2010 File No. 1-15467, as Exhibit
99.2)
|
21.
Subsidiaries of the Company
The list
of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.
(Filed
herewith.)
23.
Consents of Experts and Counsel
The
consents of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 and
23.2. (Filed herewith.)
31.
Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of
2002
Chief
Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)
Chief
Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act Of 2002 is attached hereto as Exhibit 31.2 (Filed herewith.)
32.
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is
attached hereto as Exhibit 32 (Filed herewith.)
99.1 ProLiance Holdings, LLC
Consolidated Financial Statements for the Fiscal Years Ended September 30, 2009,
2008, and 2007. (Filed herewith.)
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
VECTREN
CORPORATION
Dated
February 26,
2010
/s/ Niel C.
Ellerbrook
Niel C.
Ellerbrook,
Chairman,
Chief Executive Officer, and Director
Pursuant
to the requirements of the Securities and Exchange Act of 1934, this report has
been signed below by the following persons on behalf of the Registrant and in
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||
|
/s/
Niel C. Ellerbrook
|
Chairman,
Chief Executive Officer, and Director
|
February
26, 2010
|
||
|
Niel
C. Ellerbrook
|
(Principal
Executive Officer)
|
|||
|
/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President and Chief Financial
|
February
26, 2010
|
||
|
Jerome
A. Benkert, Jr.
|
Officer
(Principal
Financial Officer)
|
|||
|
/s/ M.
Susan Hardwick
|
Vice
President, Controller and Assistant Treasurer
|
February
26, 2010
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
|
/s/
Carl L. Chapman
|
Director
|
February
26, 2010
|
||
|
Carl
L. Chapman
|
||||
|
/s/
John M. Dunn
|
Director
|
February
26, 2010
|
||
|
John
M. Dunn
|
||||
|
/s/
John D. Engelbrecht
|
Director
|
February
26, 2010
|
||
|
John
D. Engelbrecht
|
||||
|
/s/
Anton H. George
|
Director
|
February
26, 2010
|
||
|
Anton
H. George
|
||||
|
/s/
Martin C. Jischke
|
Director
|
February
26, 2010
|
||
|
Martin
C. Jischke
|
||||
|
/s/
Robert L. Koch II
|
Director
|
February
26, 2010
|
||
|
Robert
L. Koch II
|
||||
|
/s/
William G Mays
|
Director
|
February
26, 2010
|
||
|
William
G. Mays
|
||||
|
/s/
J. Timothy McGinley
|
Director
|
February
26, 2010
|
||
|
J.
Timothy McGinley
|
||||
|
/s/
Richard P. Rechter
|
Director
|
February
26, 2010
|
||
|
Richard
P. Rechter
|
||||
|
/s/
R. Daniel Sadlier
|
Director
|
February
26, 2010
|
||
|
R.
Daniel Sadlier
|
||||
|
/s/
Michael L Smith
|
Director
|
February
26, 2010
|
||
|
Michael
L Smith
|
||||
|
/s/
Jean L. Wojtowicz
|
Director
|
February
26, 2010
|
||
|
Jean
L. Wojtowicz
|
-109- |