UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
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ý
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the fiscal year ended December 31, 2008
OR
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
transition period from __________________ to
________________________
Commission
file number: 1-16739
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VECTREN
UTILITY HOLDINGS, INC.
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(Exact
name of registrant as specified in its charter)
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INDIANA
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35-2104850
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(State
or other jurisdiction of incorporation or organization)
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(IRS
Employer Identification No.)
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One
Vectren Square
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47708
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant's
telephone number, including area code: 812-491-4000
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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Vectren Utility 6.10% SR NTS
12/1/2035
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New
York Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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Common – Without
Par
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None
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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□
*Utility Holdings is a majority
owned subsidiary of a well-known seasoned issuer, and well-known seasoned issuer
status depends in part on the type of security being registered by the
majority-owned subsidiary.
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes □ No ý
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes ý. No
□
Indicate by check mark if disclosure of
delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. ý
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer
□ Accelerated filer □
Non-accelerated
filer ý Smaller reporting company
□
(Do not
check if a smaller reporting
company)
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
The
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of June
30, 2008, was zero. All shares outstanding of the Registrant’s common
stock were held by Vectren Corporation.
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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10
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January 31, 2009
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Class
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Number
of Shares
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Date
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Omission
of Information by Certain Wholly Owned Subsidiaries
The
Registrant is a wholly owned subsidiary of Vectren Corporation and meets the
conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and
is therefore filing with the reduced disclosure format contemplated
thereby.
Definitions
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AFUDC: allowance
for funds used during construction
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MMBTU: millions
of British thermal units
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APB: Accounting
Principles Board
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MW: megawatts
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EITF: Emerging
Issues Task Force
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MWh
/ GWh: megawatt hours / thousands of megawatt hours (gigawatt
hours)
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FASB: Financial
Accounting Standards Board
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OCC: Ohio
Office of the Consumer Counselor
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FERC: Federal
Energy Regulatory Commission
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OUCC: Indiana
Office of the Utility Consumer Counselor
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IDEM: Indiana
Department of Environmental Management
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PUCO: Public
Utilities Commission of Ohio
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IURC: Indiana
Utility Regulatory Commission
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SFAS: Statement
of Financial Accounting Standards
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MCF
/ BCF: thousands / billions of cubic feet
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USEPA: United
States Environmental Protection Agency
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MDth
/ MMDth: thousands / millions of dekatherms
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Throughput: combined
gas sales and gas transportation volumes
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MISO:
Midwest Independent System Operator
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Access
to Information
Vectren
Corporation makes available all SEC filings and recent annual reports, including
those of Vectren Utility Holdings, Inc., free of charge through its website at
www.vectren.com
as soon as reasonably practicable after electronically filing or furnishing the
reports to the SEC, or by request, directed to Investor Relations at the mailing
address, phone number, or email address that follows:
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Mailing
Address:
One
Vectren Square
Evansville,
Indiana 47708
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Phone
Number:
(812)
491-4000
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Investor
Relations Contact:
Steven
M. Schein
Vice
President, Investor Relations
sschein@vectren.com
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Table
of Contents
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Item
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Page
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Number
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Number
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Part
I
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1
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1A
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1B
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2
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3
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4
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Part
II
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5
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6
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7
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7A
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8
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9
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9A
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9B
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Part
III
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10
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11
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12
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13
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14
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Part
IV
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15
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(A)
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– Omitted or amended as
the Registrant is a wholly owned subsidiary of Vectren Corporation and
meets the conditions set forth in General Instructions (I)(1)(a) and (b)
of Form 10-K and is therefore filing with the reduced disclosure format
contemplated thereby.
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PART
I
ITEM 1. BUSINESS
Description of the
Business
Vectren
Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana
corporation, was formed on March 31, 2000, to serve as the intermediate holding
company for Vectren Corporation’s (Vectren) three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North),
Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the
Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has
other assets that provide information technology and other services to the three
utilities. Vectren, an Indiana corporation, is an energy holding
company headquartered in Evansville, Indiana, and was organized on June 10,
1999. Both Vectren and Utility Holdings are holding companies as
defined by the Energy Policy Act of 2005 (Energy Act).
Indiana
Gas provides energy delivery services to over 568,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 111,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and
SIGECO generally do business as Vectren Energy Delivery of
Indiana. The Ohio operations provide energy delivery services to
approximately 317,000 natural gas customers located near Dayton in west central
Ohio. The Ohio operations are owned as a tenancy in common by Vectren
Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility
Holdings (53 percent ownership), and Indiana Gas (47 percent
ownership). The Ohio operations generally do business as Vectren
Energy Delivery of Ohio.
Narrative Description of the
Business
The
Company has 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.
At
December 31, 2008, the Company had $3.8 billion in total assets, with $2.2
billion (57 percent) attributed to Gas Utility Services, $1.4 billion (38
percent) attributed to Electric Utility Services, and $0.2 billion (5 percent)
attributed to Other Operations. Net income for the year ended
December 31, 2008, was $111.1 million, with $53.3 million attributed to the Gas
Utility Services, $50.7 million attributed to Electric Utility Services, and
$7.1 million attributed to Other Operations. Net income for the year
ended December 31, 2007, was $106.5 million. For further information
regarding the activities and assets of operating segments, refer to Note 11 in
the Company’s consolidated financial statements included under “Item 8 Financial
Statements and Supplementary Data.”
Following
is a more detailed description of the Gas Utility Services and Electric Utility
Services operating segments. The Company’s Other Operations are not
significant.
Gas
Utility Services
At
December 31, 2008, the Company supplied natural gas service to approximately
996,300 Indiana and Ohio customers, including 910,000 residential, 84,700
commercial, and 1,600 industrial and other contract
customers. Average gas utility customers served were approximately
986,700 in both 2008 and 2007; and 981,300 in 2006.
The
Company’s service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served
include automotive assembly, parts and accessories, feed, flour and grain
processing, metal castings, aluminum products, appliance manufacturing,
polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical
equipment, metal specialties, glass, steel finishing, pharmaceutical and
nutritional products, gasoline and oil products, ethanol and coal
mining. The largest Indiana communities served are Evansville,
Bloomington, Terre Haute, and suburban areas surrounding Indianapolis and
Indiana counties near Louisville, Kentucky. The largest community
served outside of Indiana is Dayton, Ohio.
Revenues
For the
year ended December 31, 2008, gas utility revenues were approximately $1,432.7
million, of which residential customers accounted for 67 percent and commercial
27 percent. Industrial and other contract customers account for the remaining 6
percent of revenues due to the high number of transportation customers in that
customer class.
The
Company receives gas revenues by selling gas directly to customers at approved
rates or by transporting gas through its pipelines at approved rates to
customers that have purchased gas directly from other producers, brokers, or
marketers. Total volumes of gas delivered to both sales and
transportation customers (throughput) were 206.3 MMDth for the year ended
December 31, 2008. Gas sold and transported to residential and
commercial customers was 114.8 MMDth representing 56 percent of
throughput. Gas transported or sold to industrial and other contract
customers was 91.5 MMDth representing 44 percent of throughput. Rates
for transporting gas generally provide for the same margins earned by selling
gas under applicable sales tariffs.
Availability
of Natural Gas
The
volume of gas sold is seasonal and affected by variations in weather
conditions. To mitigate seasonal demand, the Company’s Indiana gas
utilities have storage capacity at seven active underground gas storage fields
and six liquefied petroleum air-gas manufacturing
plants. Periodically, purchased natural gas is injected into
storage. The injected gas is then available to supplement contracted
and manufactured volumes during periods of peak requirements. The
volumes of gas per day that can be delivered during peak demand periods for each
utility are located in “Item 2 Properties.”
Natural Gas Purchasing
Activity in Indiana
The
Indiana utilities also contract with its affiliate, ProLiance Holdings, LLC
(ProLiance), to ensure availability of gas. ProLiance is an
unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens
Energy Group (Citizens). (See the discussion of Energy Marketing
& Services below and Note 3 in the Company’s Consolidated Financial
Statements included in “Item 8 Financial Statements and Supplementary Data”
regarding transactions with ProLiance). The Company also prepays
ProLiance for natural gas delivery services during the seven months prior to the
peak heating season in lieu of maintaining gas storage. The
Company received regulatory approval on April 25, 2006 from the IURC for
ProLiance to continue to provide natural gas supply services to the Company’s
Indiana utilities through March 2011.
Natural Gas Purchasing
Activity in Ohio
As a
result of a June 2005 PUCO order, the Company established an annual bidding
process for VEDO’s gas supply and portfolio administration
services. From November 1, 2005 through September 30, 2008, the
Company used a third party provider for these services. Prior to
October 31, 2005, ProLiance also supplied natural gas to Utility Holdings’ Ohio
operations.
On April
30, 2008, the PUCO issued an Order adopting a stipulation involving the Company,
the OCC and other interveners. The order involved the first
two stages of a three stage plan to exit the merchant function in the
Company’s Ohio service territory.
Stage one
of the plan was implemented on October 1, 2008 and continues through March 31,
2010. As part of stage one, wholesale suppliers that were winning bidders
in a PUCO approved auction provide the gas commodity to VEDO for resale to its
customers at auction-determined standard pricing. This standard
pricing is comprised of the monthly NYMEX settlement price plus a fixed
adder. On October 1, 2008, the Company transferred its natural gas
inventory at book value to the winning bidders, receiving proceeds of
approximately $107 million, and now purchases natural gas from those suppliers,
which include Vectren Source, a wholly owned subsidiary of Vectren, essentially
on demand. This method of purchasing gas eliminates the need for
monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits.
In the
second stage of this process, the Company will no longer sell natural gas
directly to customers; rather state- certified Competitive Retail Natural Gas
Suppliers, which are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers at auction-determined standard
pricing, and the Company will transport that gas supply to the customers.
In the third stage, which was not part of the April 2008 order, it is
contemplated that all of the Company’s Ohio customers will choose their
commodity supplier from state-certified Competitive Retail Natural Gas Suppliers
in a competitive market.
The PUCO
has also provided for an Exit Transition Cost rider for the first two stages of
the transition, which allows the Company to recover costs associated with the
transition, and it is anticipated this rider will remain effective for the
entire transition. Since the cost of gas is currently passed through
to customers through a PUCO approved recovery mechanism, the impact of exiting
the merchant function should not have a material impact on Company earnings or
financial condition.
Total Natural Gas Purchased
Volumes
In 2008,
Utility Holdings purchased 109,059 MDth volumes of gas at an average cost of
$9.61 per Dth, of which approximately 71 percent was purchased from ProLiance, 2
percent was purchased from Vectren Source, as discussed above, and 27 percent
was purchased from third party providers. The average cost of gas per
Dth purchased for the previous five years was $9.61 in 2008, $8.14 in 2007,
$8.64 in 2006, $9.05 in 2005, and $6.92 in 2004.
Electric
Utility Services
At
December 31, 2008, the Company supplied electric service to approximately
141,300 Indiana customers, including approximately 122,800 residential, 18,400
commercial, and 100 industrial and other customers. Average electric
utility customers served were approximately 141,100 in 2008; 140,800 in 2007;
and 139,700 in 2006.
The
principal industries served include polycarbonate resin (Lexan®) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, ethanol and
coal mining.
Revenues
For the
year ended December 31, 2008, retail electricity sales totaled 5,323.4 GWh,
resulting in revenues of approximately $457.3 million. Residential
customers accounted for 37 percent of 2008 revenues; commercial 28 percent;
industrial 33 percent, and municipal and other 2 percent. In
addition, in 2008 the Company sold 1,512.9 GWh through wholesale activities in
2008 principally to the MISO. Wholesale revenues, including
transmission sales, totaled $66.9 million in 2008.
System
Load
Total
load for each of the years 2004 through 2008 at the time of the system summer
peak, and the related reserve margin, is presented below in MW.
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Date
of summer peak load
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7/21/2008
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8/08/2007
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8/10/2006
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7/25/2005
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7/13/2004
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|||||||||||||||
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Total
load at peak (1)
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1,242 | 1,341 | 1,325 | 1,315 | 1,222 | |||||||||||||||
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Generating
capability
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1,295 | 1,295 | 1,351 | 1,351 | 1,351 | |||||||||||||||
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Firm
purchase supply
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135 | 130 | 107 | 107 | 105 | |||||||||||||||
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Interruptible
contracts
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62 | 62 | 62 | 76 | 51 | |||||||||||||||
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Total
power supply capacity
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1,492 | 1,487 | 1,520 | 1,534 | 1,507 | |||||||||||||||
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Reserve
margin at peak
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20 | % | 11 | % | 15 | % | 17 | % | 23 | % | ||||||||||
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(1)
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The
total load at peak is increased 25 MW in 2007-2005 from the total load
actually experienced. The additional 25 MW represents load that
would have been incurred if the Summer Cycler program had not been
activated. The 25 MW is also included in the interruptible
contract portion of the Company’s total power supply capacity in those
years. On the date of peak in 2008 and 2004, the Summer Cycler
program was not activated.
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The
winter peak load for the 2007-2008 season of approximately 960 MW occurred on
January 25, 2008. The prior year winter peak load was approximately
961 MW, occurring on December 7, 2006.
Generating
Capability
Installed
generating capacity as of December 31, 2008, was rated at 1,295
MW. Coal-fired generating units provide 1,000 MW of capacity, and
natural gas or oil-fired turbines used for peaking or emergency conditions
provide 295 MW. Electric generation for 2008 was fueled by coal (98
percent) and natural gas (2 percent). Oil was used only for testing
of gas/oil-fired peaking units. The Company generated approximately
6,653 GWh in 2008. Further information about the Company’s owned
generation is included in Item 2 Properties.
There are
substantial coal reserves in the southern Indiana area, and coal for coal-fired
generating stations has been supplied from operators of nearby coal mines,
including coal mines in Indiana owned by Vectren Fuels, Inc., a wholly owned
subsidiary of the Company. Approximately 3.2 million tons were
purchased for generating electricity during 2008, of which approximately 91
percent was supplied by Vectren Fuels, Inc. from its mines and third party
purchases. The average cost of coal paid by the utility in generating
electric energy for the years 2004 through 2008 follows:
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Year
Ended December 31,
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||||||||||||||||||||
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Average
Delivered
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2008
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2007
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2006
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2005
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2004
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|||||||||||||||
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Cost
per Ton
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$ | 42.50 | $ | 40.23 | $ | 37.51 | $ | 30.27 | $ | 27.06 | ||||||||||
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Cost
per MWh
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20.84 | 19.78 | 18.44 | 14.94 | 13.06 | |||||||||||||||
On January 1, 2009, SIGECO began purchasing coal from Vectren Fuels, Inc. (Fuels) under new coal purchase agreements. The term of these coal purchase agreements continues to December 31, 2014, with prices specified ranging from two to four years. New pricing reflects current Illinois Basin market prices and will result in substantially higher costs in 2009, compared to prior years.
Firm
Purchase Supply
The
Company maintains a 1.5 percent interest in the Ohio Valley Electric Corporation
(OVEC). OVEC is comprised of several electric utility companies,
including SIGECO, and supplies power requirements to the United States
Department of Energy’s (DOE) uranium enrichment plant near Portsmouth,
Ohio. The participating companies are entitled to receive from OVEC,
and are obligated to pay for, any available power in excess of the DOE contract
demand. At the present time, the DOE contract demand is essentially
zero. Because of this decreased demand, the Company’s 1.5 percent
interest in OVEC makes available approximately 30 MW of capacity for use in
other operations. The Company purchased approximately 236 GWh from
OVEC in 2008.
The
Company has a capacity contract with Duke Energy Marketing America, LLC. to
purchase as much as 100 MW at any time from a power plant located in Vermillion
County, Indiana. The contract ends on December 31,
2009. The Company purchased insignificant amounts under this contract
in 2008.
The
Company executed a capacity contract with Benton County Wind Farm, LLC on April
15, 2008 to purchase as much as 30 MW from a wind farm located in Benton County,
Indiana. The contract expires in 2029. At the time of peak
in 2008 approximately 5 MW was available. The Company purchased
approximately 59 GWh under this contract in 2008.
Other
Power Purchases
The
Company also purchases power as needed principally from the MISO to supplement
its generation and firm purchase supply in periods of peak
demand. Volumes purchased principally from the MISO in 2008 totaled
80 GWh.
Midwest
Independent System Operator (MISO) Capacity Purchase
In May
2008, the Company executed a MISO capacity purchase from Sempra Energy Trading,
LLC to purchase 100MW of name plate capacity from its generating facility in
Dearborn, Michigan. The term of the contract begins January 1, 2010
and continues through December 31, 2012.
Interconnections
The
Company has interconnections with Louisville Gas and Electric Company, Duke
Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier
Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and
the City of Jasper, Indiana, providing the historic ability to simultaneously
interchange approximately 500 MW. However, the ability of the Company
to effectively utilize the electric transmission grid in order to achieve its
desired import/export capability has been, and may continue to be, impacted as a
result of the ongoing changes in the operation of the Midwestern transmission
grid. The Company, as a member of the MISO, has turned over
operational control of the interchange facilities and its own transmission
assets, like many other Midwestern electric utilities, to MISO. See
“Item 7 Management’s Discussion and Analysis of Results of Operations and
Financial Condition” regarding the Company’s participation in MISO.
Competition
The
utility industry has undergone structural change for several years, resulting in
increasing competitive pressures faced by electric and gas utility
companies. Currently, several states have passed legislation allowing
electricity customers to choose their electricity supplier in a competitive
electricity market and several other states have considered such
legislation. At the present time, Indiana has not adopted such
legislation. Ohio regulation allows gas customers to choose their
commodity supplier. The Company implemented a choice program for its
gas customers in Ohio in January 2003. At December 31, 2008, over
80,000 customers in Vectren’s Ohio service territory purchase natural gas from a
supplier other than the utility. Margin earned for transporting
natural gas to those customers, who have purchased natural gas from another
supplier, are generally the same as those earned by selling gas under Ohio
tariffs. Indiana has not adopted any regulation requiring gas choice;
however, the Company operates under approved tariffs permitting certain
industrial and commercial large volume customers to choose their commodity
supplier.
Regulatory
and Environmental Matters
See “Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s regulatory environment and environmental
matters.
Personnel
As of
December 31, 2008, the Company and its consolidated subsidiaries had 1,600
employees, of which 800 are subject to collective bargaining
arrangements.
In
December 2008, the Company reached a three-year labor agreement, ending December
1, 2011 with Local 1393 of the International Brotherhood of Electrical Workers
and United Steelworkers of America Locals 12213 and 7441.
In July
2007, the Company reached a three-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2010.
In
November 2005, the Company reached a four-year agreement with Local 175 of the
Utility Workers Union of America, ending October 2009. In September
2005, the Company reached a four-year agreement with Local 135 of the Teamsters,
Chauffeurs, Warehousemen, and Helpers Union, ending September 2009.
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.
Utility
Holdings is a holding company and its assets consist primarily of investments in
its subsidiaries.
The
ability of Utility Holdings to receive dividends and repay indebtedness depends
on the earnings, financial condition, capital requirements and cash flow of its
subsidiaries, SIGECO, Indiana Gas, and VEDO and the distribution or other
payment of earnings from those entities to Utility Holdings. 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 Utility Holdings, its ability to pay dividends to its parent
could be limited. Utility Holdings’ results of operations, future
growth and earnings and dividend goals also will depend on the performance of
its subsidiaries. Additionally, certain of the Company’s lending
arrangements contain restrictive covenants, including the maintenance of a total
debt to total capitalization ratio, which could limit its ability to pay
dividends.
Continued
deterioration in general economic conditions may have adverse
impacts.
The
current economic environment is challenging and uncertain. The
consequences of a prolonged recession may include a lower level of economic
activity and uncertainty regarding energy prices and the capital and commodity
markets. Further, the risks associated with industries in which the
Company operates and serves become more acute in periods of a slowing economy or
slow growth. Economic declines may be accompanied by a decrease in
demand for natural gas and electricity. The recent economic downturn
may have some negative impact on both gas and electric large
customers. This impact may include tempered growth, significant
conservation measures, and perhaps even plant closures or
bankruptcies. Deteriorating economic conditions may also lead to
lower residential and commercial customer counts and thus lower Company
revenues. It is also highly possible that a prolonged recession could
result in increased costs including pension costs, interest costs, and bad debt
expense in excess of historical levels. Further, Vectren’s nonutility
businesses may also be negatively impacted, and those impacts could further
adversely affect Utility Holdings ability to access the capital and credit
markets.
Utility
Holdings’ gas and electric utility sales are concentrated in the
Midwest.
The
operations of the Company’s regulated utilities are concentrated in central and
southern Indiana and west central Ohio and are therefore impacted by changes in
the Midwest economy in general and changes in particular industries concentrated
in the Midwest. These industries include automotive assembly, parts
and accessories, feed, flour and grain processing, metal castings, aluminum
products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic
products, gypsum products, electrical equipment, metal specialties, glass, steel
finishing, pharmaceutical and nutritional products, gasoline and oil products,
ethanol and coal mining. While no one industrial customer comprises
10 percent of consolidated revenues, the top five industrial electric customers
comprise approximately 17 percent of electric utility revenues, and therefore
any significant decline in their collective revenues could adversely impact
operating results.
Current
financial market volatility could have adverse impacts.
The
capital and credit markets have been experiencing volatility and
disruption. If the current levels of market disruption and volatility
worsen, there can be no assurance that the Company 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’s parent, Vectren, will have access to the equity capital markets to
obtain financing when necessary or desirable.
A
downgrade (or negative outlook) in or withdrawal of Utility Holdings’ credit
ratings could negatively affect its ability to access capital and its
cost.
The
following table shows the current ratings assigned to certain outstanding debt
by Moody’s and Standard & Poor’s:
|
Current
Rating
|
||
|
Standard
|
||
|
Moody’s
|
&
Poor’s
|
|
|
Utility
Holdings and Indiana Gas senior unsecured debt
|
Baa1
|
A-
|
|
Utility
Holdings commercial paper program
|
P-2
|
A-2
|
|
SIGECO’s
senior secured debt
|
A-3
|
A
|
The
current outlook of both Standard and Poor’s and Moody’s is stable and both
categorize the ratings of the above securities as investment grade. A
security rating is not a recommendation to buy, sell, or hold
securities. The rating is subject to revision or withdrawal at any
time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade
rating is BBB- and Baa3, respectively.
Utility
Holdings 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 Utility Holdings’ ratings or, in each
case, the ratings of its subsidiaries, it may significantly limit Utility
Holdings’ access to the debt capital markets and the commercial paper market,
and the Company’s borrowing costs would increase. In addition,
Utility Holdings 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 the Company’s parent,
Vectren, will have access to the equity capital markets to obtain financing when
necessary or desirable.
Utility
Holdings 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 Utility Holdings' earnings generally and may in the
future reduce its earnings from retail electric and gas
sales. Currently, several states, including Ohio, have passed
legislation that allows customers to choose their electricity supplier in a
competitive market. Indiana has not enacted such
legislation. Ohio regulation also provides for choice of commodity
providers for all gas customers. In 2003, the Company implemented
this choice for its gas customers in Ohio and is currently in the first of the
three stage process to exit the merchant function in its Ohio service
territory. The state of Indiana has not adopted any regulation
requiring gas choice in the Company’s Indiana service territories; however, the
Company operates under approved tariffs permitting certain industrial and
commercial large volume customers to choose their commodity
supplier. Utility Holdings 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 Utility Holdings gas and electric utility sales are space
heating and cooling. Accordingly, its operating results may fluctuate
with variability of weather.
Utility
Holdings’ gas and electric utility sales are sensitive to variations in weather
conditions. The Company forecasts utility sales on the basis of
normal weather. Since Utility Holdings does not have a
weather-normalization mechanism for its electric operations, significant
variations from normal weather could have a material impact on its
earnings. However, the impact of weather on the gas operations in the
Company’s Indiana territories has been significantly mitigated through the
implementation in 2005 of a normal temperature adjustment
mechanism. Additionally, the implementation of a straight fixed
variable rate design over a two year period per a January 2009 PUCO order will
significantly mitigate weather risk related to Ohio residential gas
sales.
Risks
related to the regulation of Utility Holdings’ utility businesses, including
environmental regulation, could affect the rates the Company charges its
customers, its costs and its profitability.
Utility
Holdings’ 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, Utility
Holdings is subject to regulation by the FERC, the NERC (North American Electric
Reliability Corporation), the IURC and the PUCO. These authorities
regulate many aspects of its transmission and distribution operations, including
construction and maintenance of facilities, operations, and safety, and its gas
marketing operations involving title passage, reliability standards, and future
adequacy. In addition, these regulatory agencies approve its
utility-related debt and equity issuances, regulate the rates that the Company's
utilities can charge customers, the rate of return that Utility Holdings’
utilities are authorized to earn, and its ability to timely recover gas and fuel
costs. Further, there are consumer advocates and other
parties which may intervene in regulatory proceedings and affect regulatory
outcomes. The Company’s ability to obtain rate increases to maintain
its current authorized rate of return depends upon regulatory discretion, and
there can be no assurance that Utility Holdings will be able to obtain rate
increases or rate supplements or earn its current authorized rate of
return. As gas costs remain above historical levels and are more
volatile, any future disallowance might be material to the Company’s operations
or financial condition.
Utility
Holdings’ operations and properties are subject to extensive environmental
regulation pursuant to a variety of federal, state and municipal laws and
regulations. These environmental regulations impose, among other
things, restrictions, liabilities and obligations in connection with storage,
transportation, treatment and disposal of hazardous substances and waste and in
connection with spills, releases and emissions of various substances in the
environment. Such emissions from electric generating facilities
include particulate matter, sulfur dioxide (SO2), nitrogen
oxide (NOx), and mercury, among others.
Environmental
legislation also requires that facilities, sites and other properties associated
with the Company'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 Utility Holdings subject to environmental
regulation, its investment in environmentally compliant equipment, and the costs
associated with operating that equipment, have increased and are expected to
increase in the future.
Climate
Change
Further,
there are proposals to address global climate change that would regulate carbon
dioxide (CO2) and other
greenhouse gases and other proposals that would mandate an investment in
renewable energy sources. Any future legislative or regulatory
actions taken to address global climate change or mandate renewable energy
sources could substantially affect both the costs and operating characteristics
of the Company’s fossil fuel generating plants and possibly natural gas
distribution businesses. Further, any legislation would likely impact
the Company’s generation resource planning decisions. At this time and in
the absence of final legislation, compliance costs and other effects associated
with reductions in greenhouse gas emissions or obtaining renewable energy
sources remain uncertain. The Company has gathered preliminary estimates
of the costs to comply with a cap and trade approach to controlling greenhouse
gas emissions. A preliminary investigation demonstrated costs to
comply would be significant, first to operating expenses for the purchase of
allowances, and later to capital expenditures as technology becomes available to
control greenhouse gas emissions. However, these compliance cost
estimates are very sensitive to highly uncertain assumptions, including
allowance prices. Costs to purchase allowances that cap greenhouse
gas emissions should be considered a cost of providing electricity, and as such,
the Company believes recovery should be timely reflected in rates charged to
customers. Approximately 22 percent of electric volumes sold in 2008
were delivered to municipal and other wholesale customers. As such,
the Company has some flexibility to modify the level of these transactions to
reduce overall emissions and reduce costs associated with complying with new
environmental regulations.
From
time to time, Utility Holdings is subject to material litigation and regulatory
proceedings.
From time
to time, the Company 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 Utility
Holdings’ business, prospects, results of operations, or financial
condition.
Utility
Holdings’ 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.
Utility
Holdings’ regulated electric utility engages in wholesale power marketing
activities that primarily involve the offering of utility-owned or contracted
generation into the MISO hourly and real time markets. As part of
these strategies, the Company may also execute energy contracts that are
integrated with portfolio requirements around power supply and
delivery. Margin earned from these activities above or below $10.5
million is shared evenly with customers. These earnings from
wholesale marketing activities may vary based on fluctuating prices for
electricity and the amount of electric generating capacity or purchased power
available, beyond that needed to meet firm service requirements.
Catastrophic
events could adversely affect Utility Holdings’ facilities and
operations.
Catastrophic
events such as fires, earthquakes, explosions, floods, ice storms, tornados,
terrorist acts or other similar occurrences could adversely affect Utility
Holdings’ facilities, operations, financial condition and results of
operations.
Workforce
risks could affect Utility Holdings’ 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.
The
performance of Vectren’s nonutility businesses may impact Utility
Holdings.
Execution
of gas marketing strategies by ProLiance and Vectren’s nonutility gas retail
supply operations as well as the execution of Vectren’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 gas 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. Credit ratings of
individual entities within a consolidated organization can be influenced by
changes in business prospects and developments of other entities within that
organization. Thus, material adverse developments affecting
those other entities related to Vectren could result in a downgrade in
Utility Holdings’ credit ratings or outlook, limit its ability to access the
debt markets, bank financing and commercial paper markets and, thus, its
liquidity.
Vectren’s
nonutility businesses support Utility Holdings’ 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 approval and
negotiations 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 altered.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Gas Utility
Services
Indiana
Gas owns and operates four active gas storage fields located in Indiana covering
58,100 acres of land with an estimated ready delivery from storage capability of
6.0 BCF of gas with maximum peak day delivery capabilities of 151,000 MCF per
day. Indiana Gas also owns and operates three liquefied petroleum
(propane) air-gas manufacturing plants located in Indiana with the ability to
store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of
manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted with ProLiance for 17.9 BCF
of prepaid delivery service with a maximum peak day delivery capability of
298,600 MMBTU per day. Indiana Gas’ gas delivery system includes
12,900 miles of distribution and transmission mains, all of which are in Indiana
except for pipeline facilities extending from points in northern Kentucky to
points in southern Indiana so that gas may be transported to Indiana and sold or
transported by Indiana Gas to ultimate customers in Indiana.
SIGECO
owns and operates three active underground gas storage fields located in Indiana
covering 6,100 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
108,500 MCF per day. In addition to its company owned storage
delivery capabilities, SIGECO has contracted with ProLiance for 0.5 BCF of
prepaid delivery service with a maximum peak day delivery capability of 19,200
MMBTU per day. SIGECO's gas delivery system includes 3,200 miles of
distribution and transmission mains, all of which are located in
Indiana.
The Ohio
operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants, all of which are located in Ohio. The plants
can store 0.5 million gallons of propane, and the plants can manufacture for
delivery 52,200 MCF of manufactured gas per day. In addition to its
propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF
of delivery service with a maximum peak day delivery capability of 246,100 MMBTU
per day. While the Company still has title to this delivery
capability, it has released it to those now supplying the Ohio operations with
natural gas, and those suppliers are responsible for the demand
charges. The Ohio operations’ gas delivery system includes 5,500
miles of distribution and transmission mains, all of which are located in
Ohio.
Electric Utility
Services
SIGECO's
installed generating capacity as of December 31, 2008, was rated at 1,295
MW. SIGECO's coal-fired generating facilities are the Brown Station
with two units of 490 MW of combined capacity, located in Posey County
approximately eight miles east of Mt. Vernon, Indiana; the Culley Station
with two units of
360 MW of combined capacity, and Warrick Unit 4 with 150 MW of
capacity. Both the Culley and Warrick Stations are located in Warrick
County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4)
located at the Brown Station; two Broadway Avenue Gas Turbines located in
Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1,
50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located
northeast of Evansville in Vanderburgh County, Indiana with a combined capacity
of 20 MW. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are
also equipped to burn oil. Total capacity of SIGECO's six gas
turbines is 295 MW, and they are generally used only for reserve, peaking, or
emergency purposes due to the higher per unit cost of generation.
SIGECO's
transmission system consists of 924 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 32 substations with an
installed capacity of 4,200 megavolt amperes (Mva). The electric
distribution system includes 4,200 pole miles of lower voltage overhead lines
and 349 trench miles of conduit containing 2,000 miles of underground
distribution cable. The distribution system also includes 98
distribution substations with an installed capacity of 2,900 Mva and 54,000
distribution transformers with an installed capacity of 2,500 Mva.
SIGECO
owns utility property outside of Indiana approximating nine miles of 138,000
volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Property Serving as
Collateral
SIGECO's
properties are subject to the lien of the First Mortgage Indenture dated as of
April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and
Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM 3. LEGAL PROCEEDINGS
The
Company is party to various legal proceedings arising in the normal course of
business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position, results of operations, or cash
flows. See the notes to the consolidated financial statements
regarding commitments and contingencies, environmental matters, rate and
regulatory matters. The consolidated financial statements are
included in “Item 8 Financial Statements and Supplementary Data.”
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY
HOLDERS
No
matters were submitted during the fourth quarter to a vote of security
holders.
PART
II
Common
Stock Market Price
All of
the outstanding shares of Utility Holdings’ common stock are owned by
Vectren. Utility Holdings’ common stock is not
traded. There are no outstanding options or warrants to purchase
Utility Holdings’ common equity or securities convertible into Utility Holdings’
common equity. Additionally, Utility Holdings has no plans to
publicly offer its common equity securities.
Dividends
Paid to Parent
During
2008, Utility Holdings paid dividends to its parent company totaling $20.8
million in each quarter.
During
2007, Utility Holdings paid dividends to its parent company totaling $19.1
million in each quarter.
In the
first quarter of 2009, the board of directors declared a $20.6 million dividend,
payable to Vectren.
Dividends
on shares of common stock are payable at the discretion of the board of
directors out of legally available funds. Future payments of
dividends, and the amounts of these dividends, will depend on the Company’s
financial condition, results of operations, capital requirements, and other
factors. 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)
|
2008
|
2007
|
2006
|
2005
|
2004
|
|||||||||||||||
|
Operating
Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 1,958.7 | $ | 1,759.0 | $ | 1,656.5 | $ | 1,781.8 | $ | 1,498.0 | ||||||||||
|
Operating
income
|
254.6 | 244.4 | 209.0 | 216.6 | 196.3 | |||||||||||||||
|
Income
before cumulative effect of change
|
||||||||||||||||||||
|
in
accounting principle
|
111.1 | 106.5 | 91.4 | 95.1 | 83.1 | |||||||||||||||
|
Net
income
|
111.1 | 106.5 | 91.4 | 95.1 | 83.1 | |||||||||||||||
|
Balance
Sheet Data:
|
||||||||||||||||||||
|
Total
assets
|
$ | 3,838.1 | $ | 3,643.7 | $ | 3,440.8 | $ | 3,391.2 | $ | 3,147.7 | ||||||||||
|
Redeemable
preferred stock
|
- | - | - | - | 0.1 | |||||||||||||||
|
Long-term
debt - net of current maturities
|
||||||||||||||||||||
|
&
debt subject to tender
|
1,065.1 | 1,062.6 | 1,025.3 | 997.8 | 941.3 | |||||||||||||||
|
Common
shareholder's equity
|
1,242.9 | 1,090.4 | 1,056.7 | 1,023.8 | 985.4 | |||||||||||||||
|
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
|
Utility
Holdings generates revenue primarily from the delivery of natural gas and
electric service to its customers. Utility Holdings’ primary source of
cash flow results from the collection of customer bills and the payment for
goods and services procured for the delivery of gas and electric
services.
Vectren
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 Utility Holdings’ SEC filings.
|
The
following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes
thereto.
|
Executive Summary of
Consolidated Results of Operations
Results
In 2008,
the Utility Holdings’ earnings were $111.1 million compared to $106.5 million in
2007. The 4 percent increase is due primarily to a full year of base
rate changes in the Indiana service territories and increased earnings from
wholesale power operations. Increases were offset somewhat by
increased operating costs associated with maintenance and reliability programs
contemplated in the base rate cases and favorable weather in 2007.
In 2007
compared to 2006, the increase in earnings primarily resulted from base rate
increases in the Vectren South service territory, the combined impact of
residential and commercial usage and lost margin recovery, favorable weather,
and increased wholesale power margins. The increase was offset
somewhat by increased operating costs including depreciation expense in 2007 and
a lower effective tax rate in 2006.
In the
Company’s electric and Ohio natural gas service territories which are not
protected by weather normalization mechanisms, management estimates the margin
impact of weather to be approximately $1.2 million favorable or $0.7 million
after tax compared to 30-year normal temperatures in 2008. In 2007
management estimates a $5.5 million favorable impact on margin compared to
normal or $3.3 million after tax, and in 2006 an $8.3 million unfavorable impact
on margin compared to normal or $4.9 million after tax.
2009
Ice Storm
On
January 27, 2009, a major ice storm in the Company’s southern Indiana territory
resulted in an extended disruption of electricity to approximately 75,000 of the
Company’s 141,000 electric customers. Electricity was restored to
substantially all customers within one week. Management estimates the
total cost of restoration could approximate $15 to $20 million, the majority of
which is expected to be capitalized as utility plant.
Results of
Operations
Significant
Fluctuations
Margin
Throughout
this discussion, the terms Gas Utility margin and Electric Utility margin are
used. Gas Utility margin is calculated as Gas utility revenues less the
Cost of
gas. Electric Utility margin is calculated as Electric utility revenues
less Cost of fuel &
purchased power. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar-for-dollar basis from customers.
Sales of
natural gas and electricity to residential and commercial customers are seasonal
and are impacted by weather. Trends in average use among natural gas
residential and commercial customers have tended to decline in recent years as
more efficient appliances and furnaces are installed and the price of natural
gas has increased. Normal temperature adjustment (NTA) and lost margin
recovery mechanisms largely mitigate the effect on Gas Utility margin that would
otherwise be caused by variations in volumes sold to these customers due to
weather and changing consumption patterns. Indiana Gas’ territory has both
an NTA since 2005 and lost margin recovery since December 2006. SIGECO’s
natural gas territory has an NTA since 2005, and lost margin recovery began when
new base rates went into effect August 1, 2007. The Ohio service territory
had lost margin recovery since October 2006. The Ohio lost margin
recovery mechanism ended when new base rates went into effect in February
2009. This mechanism was replaced by a rate design, commonly referred
to as a straight fixed variable rate design, which is more dependent on service
charge revenues and less dependent on volumetric revenues than previous rate
designs. This new rate design, which will be phased in over a two year period,
also prospectively mitigates some weather risk in Ohio. SIGECO’s
electric service territory has neither NTA nor lost margin recovery
mechanisms.
Gas and
electric margin generated from sales to large customers (generally industrial
and other contract customers) is primarily impacted by overall economic
conditions and changes in demand for those customers’ products. The
recent recession may have some negative impact on both gas and electric large
customers. This impact may include tempered growth, significant
conservation measures, and perhaps even plant closures or
bankruptcies. While no one industrial customer comprises 10 percent
of consolidated revenues, the top five industrial electric customers comprise
approximately 17 percent of electric utility revenues, and therefore any
significant decline in their collective revenues could adversely impact
operating results. Deteriorating economic conditions may also lead to
continued lower residential and commercial customer counts.
Margin is
also impacted by the collection of state mandated taxes, which fluctuate with
gas and fuel costs, as well as other tracked expenses. Expenses
subject to tracking mechanisms include Ohio bad debts and percent of income
payment plan expenses, Indiana gas pipeline integrity management costs, and
costs to fund Indiana energy efficiency programs. Certain operating
costs associated with operating environmental compliance equipment were also
tracked prior to their recovery in base rates that went into effect on August
15, 2007. The latest Indiana service territory rate cases,
implemented in 2007 and 2008 also provide for the tracking of MISO revenues and
costs, as well as the gas cost component of bad debt expense based on historical
experience and unaccounted for gas. Unaccounted for gas is also
tracked in the Ohio service territory.
Electric
wholesale activities are primarily affected by market conditions, the level of
excess generating capacity, and electric transmission availability.
Following is a discussion and analysis of margin generated from regulated
utility operations.
Gas
Utility Margin (Gas utility revenues less Cost of gas)
Gas
Utility margin and throughput by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Gas
utility revenues
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Cost
of gas sold
|
983.1 | 847.2 | 841.5 | |||||||||
|
Total
gas utility margin
|
$ | 449.6 | $ | 422.2 | $ | 391.0 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 385.1 | $ | 360.9 | $ | 330.2 | ||||||
|
Industrial
customers
|
52.2 | 48.7 | 48.0 | |||||||||
|
Other
|
12.3 | 12.6 | 12.8 | |||||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
114.8 | 108.4 | 97.7 | |||||||||
|
Industrial
customers
|
91.5 | 86.2 | 84.9 | |||||||||
|
Total
sold & transported volumes
|
206.3 | 194.6 | 182.6 | |||||||||
For the
year ended December 31, 2008, gas utility margins were $449.6 million, an
increase of $27.4 million compared to 2007. The Vectren North base
rate increase, effective February 14, 2008 added $11.8 million in
margin. Also impacting year over year results was the Vectren South
base rate increase, effective August 1, 2007, increasing margin for the full
2008 year approximately $3.6 million. In 2008, Ohio weather was 8
percent colder than the prior year and resulted in an estimated increase in
margin of approximately $3.2 million compared to 2007. Operating
costs, including revenue and usage taxes, directly recovered in margin,
increased gas margin $7.8 million. The average cost per dekatherm of gas
purchased for the year ended December 31, 2008, was $9.61 compared to $8.14 in
2007 and $8.64 in 2006.
Gas
Utility margins increased $31.2 million in 2007 compared to
2006. Residential and commercial customer usage, including lost
margin recovery, increased margin $13.3 million year over year. For
all of 2007, Ohio weather was 6 percent warmer than normal, but approximately 6
percent colder than the prior year and resulted in an estimated increase in
margin of approximately $2.0 million compared to 2006. Margin
increases associated with the Vectren South base rate increase, effective August
1, 2007, were $3.3 million. Recovery of gas storage carrying costs in
Ohio was $2.3 million. Lastly, operating costs, including revenue and
usage taxes, directly recovered in margin increased gas margin $10.3 million
year over year. During 2007, the Company resolved all remaining
issues related to a 2005 disallowance by the PUCO of gas costs incurred by the
Ohio utility operations, resulting in an additional charge of $1.1
million.
Electric
Utility Margin (Electric Utility revenues less Cost of fuel and purchased
power)
Electric
Utility margin and volumes sold by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Electric
utility revenues
|
$ | 524.2 | $ | 487.9 | $ | 422.2 | ||||||
|
Cost
of fuel & purchased power
|
182.9 | 174.8 | 151.5 | |||||||||
|
Total
electric utility margin
|
$ | 341.3 | $ | 313.1 | $ | 270.7 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 218.6 | $ | 198.6 | $ | 162.9 | ||||||
|
Industrial
customers
|
82.9 | 78.3 | 70.2 | |||||||||
|
Municipals
& other customers
|
7.3 | 15.3 | 24.0 | |||||||||
|
Subtotal:
Retail
|
$ | 308.8 | $ | 292.2 | $ | 257.1 | ||||||
|
Wholesale
margin
|
$ | 32.5 | $ | 20.9 | $ | 13.6 | ||||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
2,850.5 | 3,042.9 | 2,789.7 | |||||||||
|
Industrial
customers
|
2,409.1 | 2,538.5 | 2,570.4 | |||||||||
|
Municipals
& other
|
63.8 | 635.1 | 644.4 | |||||||||
|
Total
retail & firm wholesale volumes sold
|
5,323.4 | 6,216.5 | 6,004.5 | |||||||||
Retail
Electric
retail utility margin was $308.8 million for the year ended December 31, 2008,
an increase of approximately $16.6 million compared to 2007. The base
rate increase that went into effect on August 15, 2007, produced incremental
margin of $27.0 million year over year when netted with municipal contracts that
were allowed to expire. Management estimates the year over year
decreases in usage by residential and commercial customers due to weather, which
was very warm the prior summer, to be $7.5 million. Other usage
declines due in part to a weakening economy and conservation measures were the
primary reason for the remaining decrease.
In 2007,
electric retail utility margins increased $35.1 million when compared to
2006. Management estimates the year over year increases in usage by
residential and commercial customers due to weather to be $11.8
million. The base rate increase that went into effect on August 15,
2007, produced incremental margin of $17.9 million. During 2007,
cooling degree days were 33 percent above normal compared to 5 percent below
normal in 2006. Recovery of pollution control investments and
expenses increased margin $5.5 million year over year.
Margin
from Wholesale Activities
Periodically,
generation capacity is in excess of native load. The Company markets
and sells this unutilized generating and transmission capacity to optimize the
return on its owned assets. A majority of the margin generated from
these activities is associated with wholesale off-system sales, and
substantially all off-system sales occur into the MISO Day Ahead and Real Time
markets.
Further
detail of Wholesale
activity follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Off-system
sales, net of sharing in 2008
|
$ | 23.2 | $ | 16.9 | $ | 14.2 | ||||||
|
Transmission
system sales
|
9.3 | 4.0 | 3.5 | |||||||||
|
Other
|
- | - | (4.1 | ) | ||||||||
|
Total
wholesale margin
|
$ | 32.5 | $ | 20.9 | $ | 13.6 | ||||||
For the
year ended December 31, 2008, wholesale margins were $32.5 million, representing
an increase of $11.6 million, compared to 2007.
During
2008, margin from off-system sales retained by the Company increased $6.3
million. The Company experienced higher wholesale power marketing
margins due to the increase in off peak volumes available for sale off system,
driven primarily by expiring municipal contracts, and increases in wholesale
prices. The base rate case effective August 17, 2007, requires that
wholesale margin from off-system sales earned above or below $10.5 million be
shared equally with customers, and 2008 results reflect the impact of that
sharing. Off-system sales totaled 1,512.9 GWh in 2008, compared to
921.3 GWh in 2007 and 889.4 GWh in 2006.
Beginning
in June 2008, the Company began earning a return on electric transmission
projects constructed by the Company in its service territory that benefit
reliability throughout the region. These returns primarily account
for the year over year increase of $4.8 million in transmission system
sales.
For the
year ended December 31, 2007, wholesale margins were $20.9 million, which
represents an increase of $7.3 million, compared to 2006. The
increase is primarily due to losses on financial contracts experienced in 2006
and higher fourth quarter wholesale prices. In 2006, the availability
of excess capacity was reduced by scheduled outages associated with the
installation of environmental compliance equipment.
Operating
Expenses
Other
Operating
For the
year ended December 31, 2008, other operating expenses were
$300.3 million, which represents an increase of $34.2 million, compared to
2007. Costs in 2008 resulting from increased maintenance and other
reliability activities, including amortization of prior deferred costs
contemplated in base rate increases, increased approximately $35.3 million year
over year. Operating costs that are directly recovered in utility
margin increased $4.2 million year over year. Costs associated with
lower performance compensation and share based compensation and other cost
reductions partially offset these increases.
In 2007,
other operating
expenses increased $27.1 million compared to 2006. Operating
costs that are directly recovered in utility margin, including costs funding
Indiana energy efficiency programs, increased $9.5 million year over
year. Increases in operating costs associated with lost margin
recovery and conservation initiatives that are not directly recovered in margin
increased $1.3 million year over year. Costs directly attributable to
the Vectren South rate cases, including amortization of prior deferred costs,
totaled $3.6 million in 2007. Expenses in 2006 are offset by the gain
on the sale of a storage asset of approximately $4.4 million. The
remaining increases are primarily due to increased wage and benefit
costs.
Depreciation
& Amortization
Depreciation
expense increased $7.1 million in 2008 compared to 2007 as well as in 2007
compared to 2006. Expense in 2008 and 2007 includes $3.8 million and
$1.8 million, respectively of increased amortization associated with prior
electric demand side management costs pursuant to the August 15,
2007 electric base rate order. The remaining increases are also
attributable to increased utility plant in service.
Taxes
Other Than Income Taxes
Taxes
other than income taxes increased $4.2 million in 2008 compared to 2007 and
increased $3.9 million in 2007 compared 2006. The increases are
primarily attributable to higher utility receipts, excise, and usage
taxes. These variations resulted primarily from volatility in
revenues and gas volumes sold.
Other
Income-Net
Other-net reflects income of
$4.0 million in 2008 compared to $9.4 million in 2007 and $7.6 million in
2006. The decrease in 2008 compared to 2007 is primarily due to lower
returns associated with investments that fund deferred compensation arrangements
and lower interest income. The increase in 2007 compared to 2006
relates primarily to increased AFUDC due to increased capital spending and
higher interest income.
Interest
Expense
For the
year ended December 31, 2008, interest expense was $79.9 million, a decrease of
$0.7 million compared to 2007, as lower average short-term debt levels and lower
average short-term interest rates were partially offset by higher long-term
balances and interest rates.
In 2007,
interest expense increased $3.1 million compared to 2006. The
increase is primarily driven by rising interest rates during the period and is
also impacted by higher levels of short-term borrowings. The 2007
increase was mitigated somewhat by the full impact of financing transactions
completed in October 2006. Interest costs in 2006 reflect permanent
financing transactions completed in the fourth quarter of 2005 in which $150
million in debt-related proceeds were received and used to retire short-term
borrowings and other long-term debt.
Income
Taxes
Federal
and state income taxes
increased $0.9 million in 2008 compared to 2007 and $19.0 million in 2007
compared to 2006. The changes are impacted primarily by fluctuations
in pre-tax income and a lower effective tax rate in 2008 and 2006.
Environmental
Matters
The
Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water
quality. Pursuant to environmental regulations, the Company is
required to obtain operating permits for the electric generating plants that it
owns or operates and construction permits for any new plants it might propose to
build. Regulations concerning air quality establish standards with
respect to both ambient air quality and emissions from electric generating
facilities, including particulate matter, sulfur dioxide (SO2), nitrogen
oxide (NOx), and mercury. Regulations concerning water quality
establish standards relating to intake and discharge of water from electric
generating facilities, including water used for cooling purposes in electric
generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations.
Clean Air Act
Initiatives
In March
of 2005, the USEPA finalized the Clean Air Interstate Rule (CAIR). CAIR is an
allowance cap and trade program requiring further reductions from coal-burning
power plants in NOx emissions beginning January 1, 2009 and SO2 emissions
beginning January 1, 2010, with a second phase of reductions in 2015. On
July 11, 2008, the US Court of Appeals for the District of Columbia vacated the
federal CAIR regulations. Various parties filed motions for
reconsideration, and on December 23, 2008, the Court reinstated the CAIR
regulations and remanded the regulations back to the USEPA for promulgation of
revisions in accordance with the Court’s July 11, 2008 Order. Thus,
the original version of CAIR promulgated in March of 2005 remains effective
while USEPA revises it per the Court’s guidance. It is possible that
a revised CAIR will require further reductions in NOx and SO2 from
SIGECO’s generating units. SIGECO is in compliance with the current
CAIR Phase I annual NOx reduction requirements in effect on January 1,
2009. Utilization of the Company’s inventory of NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of the these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. It is quite possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress. It is also possible that the USEPA will promulgate
a revised mercury regulation in 2009.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. Prior to being included in base rates, return
on investments made and recovery of related operating expenses were recovered
through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. Through
December 31, 2008, the Company has invested approximately $97.6 million in this
project. The scrubber was placed into service on January 1, 2009, and
the Company expects the total project investment to approximate $100 million
once all post in-service investments are completed. Recovery through
a rider mechanism of associated operating expenses including depreciation
expense associated with the scrubber also began on January 1,
2009. With the SO2 scrubber
fully operational, SIGECO is positioned for compliance with the additional
SO2
reductions required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s
coal fired generating fleet is 100 percent scrubbed for SO2 and 90
percent controlled for NOx. SIGECO's investments in scrubber, SCR and
fabric filter technology allows for compliance with existing regulations and
should position it to comply with future reasonable pollution control
legislation, if and when, reductions in mercury and further reductions in NOx
and SO2 are
promulgated by USEPA.
Climate
Change
The
Company is committed to responsible environmental stewardship and conservation
efforts as demonstrated by its proactive approach to balancing environmental and
customer needs. While scientific uncertainties exist and the debate surrounding
global climate change is ongoing, the growing understanding of the science of
climate change would suggest a strong potential for adverse economic and social
consequences should world-wide carbon dioxide (CO2) and other
greenhouse gas emissions continue at present levels.
The need
to reduce CO2 and other
greenhouse gas emissions, yet provide affordable energy requires thoughtful
balance. For these reasons, the Company supports a national climate change
policy with the following elements:
|
·
|
An
inclusive scope that involves all sectors of the economy and sources of
greenhouse gases, and recognizes early actions and investments made to
mitigate greenhouse gas emissions;
|
|
·
|
Provisions
for enhanced use of renewable energy sources as a supplement to base load
coal generation including effective energy conservation, demand side
management and generation efficiency
measures;
|
|
·
|
A
flexible market-based cap and trade approach with zero cost allowance
allocations to coal-fired electric generators. The approach
should have a properly designed economic safety valve in order to reduce
or eliminate extreme price spikes and potential price volatility. A long
lead time must be included to align nearer-term technology capabilities
and expanded generation efficiency and other enhanced renewable
strategies, ensuring that generation sources will rely less on natural gas
to meet short term carbon reduction requirements. This new
regime should allow for adequate resource and generation planning and
remove existing impediments to efficiency enhancements posed by the
current New Source Review provisions of the Clean Air
Act;
|
|
·
|
Inclusion
of incentives for investment in advanced clean coal technology and support
for research and development; and
|
|
·
|
A
strategy supporting alternative energy technologies and biofuels and
increasing the domestic supply of natural gas to reduce dependence on
foreign oil and imported natural
gas.
|
Current
Initiatives to Increase Conservation and Reduce Emissions
The
Company is committed to its policy on climate change and conservation. Evidence
of this commitment includes:
|
·
|
Focusing
the Company’s mission statement and purpose on corporate sustainability
and the need to help customers conserve and manage energy
costs;
|
|
·
|
Recently
executing a 20 year contract to purchase 30MW of wind energy generated by
a wind farm in Benton County,
Indiana;
|
|
·
|
Evaluating
other renewable energy projects to complement base load coal fired
generation in advance of mandated renewable energy portfolio
standards;
|
|
·
|
Implementing
conservation initiatives in the Company’s Indiana and Ohio gas utility
service territories;
|
|
·
|
Participation
in an electric conservation and demand side management collaborative with
the OUCC and other customer advocate
groups;
|
|
·
|
Evaluating
potential carbon requirements with regard to new generation, other fuel
supply sources, and future environmental compliance
plans;
|
|
·
|
Reducing
the Company’s carbon footprint by measures such as purchasing hybrid
vehicles, and optimizing generation
efficiencies;
|
|
·
|
Developing
renewable energy and energy efficiency performance contracting projects
through its wholly owned subsidiary, Energy Systems
Group.
|
Legislative
Actions and Other Climate Change Initiatives
There are
currently several forms of legislation being circulated at the federal level
addressing the climate change issue. These proposals generally
involve either: 1) a “cap and trade” approach where there is a progressive cap
on greenhouse gas emissions and an auctioning and subsequent trading of
allowances among those that emit greenhouse gases or 2) a carbon
tax. Currently no legislation has passed either house of
Congress.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in the State
of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas
Reduction Accord, and its legislature has in the recent past debated, but did
not pass, renewable energy portfolio standards. It is expected that
the Indiana State legislature will address a renewable energy portfolio standard
again in 2009.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from new motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. Should the USEPA find such endangerment, it is likely
that major stationary sources will be subject to regulation under the
Act. In 2008, the USEPA published its Advanced Notice of Proposed
Rulemaking in which the agency solicited comment as to whether it is appropriate
or effective to regulate greenhouse gas emissions under the Act. The
Obama administration has asserted that it will act on the endangerment finding
in the absence of comprehensive federal legislation within the next 18
months.
Impact
of Legislative Actions and Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants and
possibly natural gas distribution businesses. Further, any legislation
would likely impact the Company’s generation resource planning decisions.
At this time and in the absence of final legislation, compliance costs and other
effects associated with reductions in greenhouse gas emissions or obtaining
renewable energy sources remain uncertain. The Company has gathered
preliminary estimates of the costs to comply with a cap and trade approach to
controlling greenhouse gas emissions. A preliminary investigation
demonstrated costs to comply would be significant, first to operating expenses
for the purchase of allowances, and later to capital expenditures as technology
becomes available to control greenhouse gas emissions. However, these
compliance cost estimates are very sensitive to highly uncertain assumptions,
including allowance prices. Costs to purchase allowances that cap
greenhouse gas emissions should be considered a cost of providing electricity,
and as such, the Company believes recovery should be timely reflected in rates
charged to customers. Approximately 22 percent of electric volumes
sold in 2008 were delivered to municipal and other wholesale
customers. As such, the Company has some flexibility to modify the
level of these transactions to reduce overall emissions and reduce costs
associated with complying with new environmental regulations.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that owned or
operated these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded cumulative costs
that it reasonably expects to incur totaling approximately $21.6
million. The estimated accrued costs are limited to Indiana Gas’
share of the remediation efforts. Indiana Gas has arrangements in
place for 19 of the 26 sites with other potentially responsible parties (PRP),
which serve to limit Indiana Gas’ share of response costs at these 19 sites to
between 20 percent and 50 percent.
With
respect to insurance coverage, Indiana Gas has received and recorded settlements
from all known insurance carriers under insurance policies in effect when these
plants were in operation in an aggregate amount approximating $20.5
million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has filed a declaratory judgment action against its insurance carriers seeking a
judgment finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit. While the total costs that may be incurred in connection
with addressing these sites cannot be determined at this time, SIGECO has
recorded cumulative costs that it reasonably expects to incur totaling
approximately $8.7 million. With respect to insurance coverage,
SIGECO has received and recorded settlements from insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.0 million.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. While
the Company’s utilities have recorded all costs which they presently expect to
incur in connection with activities at these sites, it is possible that future
events may require some level of additional remedial activities which are not
presently foreseen and those costs may not be subject to PRP or insurance
recovery. As of December 31, 2008, approximately $6.5 million is
included in Other
Liabilities related to the remediation of these sites.
Jacobsville Superfund
Site
On July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The
USEPA has identified four sources of historic lead
contamination. These four sources shut down manufacturing operations
years ago. When drawing up the boundaries for the listing, the USEPA
included a 250 acre block of properties surrounding the Jacobsville
neighborhood, including the Company's Wagner Operations Center. The
Company’s property has not been named as a source of the lead contamination, nor
does the USEPA's soil testing to date indicate that the property contains lead
contaminated soils. The Company's own soil testing, completed during
the construction of the Operations Center, did not indicate that the property
contains lead contaminated soils. At this time, the Company
anticipates only additional soil testing could be requested by the USEPA at some
future date.
Rate
and Regulatory Matters
Gas and
electric operations with regard to retail rates and charges, terms of service,
accounting matters, issuance of securities, and certain other operational
matters specific to its Indiana customers are regulated by the
IURC. The retail gas operations of the Ohio operations are subject to
regulation by the PUCO.
Gas rates
in Indiana contain a gas cost adjustment (GCA) clause. The GCA clause allows the
Company to charge for changes in the cost of purchased gas. Electric
rates contain a fuel adjustment clause (FAC) that allows for adjustment in
charges for electric energy to reflect changes in the cost of
fuel. The net energy cost of purchased power, subject to a variable
benchmark based on NYMEX natural gas prices, is also recovered through
regulatory proceedings. The IURC approved agreement authorizing this
recovery expires in April 2010, and is subject to automatic annual
renewals.
GCA and
FAC procedures involve periodic filings and IURC hearings to establish the
amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. The Company records any
under-or-over-recovery resulting from gas and fuel adjustment clauses each month
in margin. A corresponding asset or liability is recorded until the
under-or-over-recovery is billed or refunded to utility customers.
The IURC
has also applied the statute authorizing GCA and FAC procedures to reduce rates
when necessary to limit net operating income to a level authorized in its last
general rate order through the application of an earnings test. These
earnings tests have not had any material impact to the Company’s recent
operating results.
Prior to
October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery
(GCR) clause. The GCR clause operated similar to the GCA clause in
Indiana. The PUCO periodically audited the GCR rates. The period
from November 2005 to September 2008, the final GCR period subject to audit, is
currently under audit by the PUCO. After October 1st, the
Company is no longer the supplier, and the GCR is no longer
necessary.
Vectren Energy Delivery
Ohio, Inc. (VEDO) Gas Base Rate Order Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also adjusts the rate design that will be used to collect the agreed-upon
revenue from VEDO's residential customers. The order authorizes the
use of a straight fixed variable rate design which places all, or most, of the
fixed cost recovery in the customer service charge. Using a phased in
approach, revenues based on volumes sold will be entirely replaced with a fixed
charge after one year. A straight fixed variable design
mitigates some weather risk as well as the effects of declining usage, similar
to the Company’s lost margin recovery mechanism, which expired when this new
rate design went into effect in February 2009. In 2008, results include
approximately $4.3 million of revenue from the existing lost margin recovery
mechanism that will not continue once this base rate increase is in
effect. The OCC has filed a request for rehearing on the rate design
finding by the PUCO. The rehearing request mirrors similar requests
filed by the OCC in each case where the PUCO has approved similar rate designs,
and all such requests have been denied.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of bad debt and percent of
income payment plan (PIPP) expenses; base rate recovery of pipeline integrity
management expense; timely recovery of costs associated with the accelerated
replacement of bare steel and cast iron pipes, as well as certain service
risers; and expanded conservation programs now totaling up to $5 million in
annual expenditures.
Vectren Energy Delivery
Ohio, Inc. Begins Process to Exit the Merchant Function
On August
20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers
to provide the gas commodity to the Company for resale to its customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. This auction, which is effective from October 1, 2008 through
March 31, 2010, is the initial step in exiting the merchant function in the
Company’s Ohio service territory. The approach eliminates the
need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits. On October 1st, VEDO’s
entire natural gas inventory was transferred, receiving proceeds of
approximately $107 million. The PUCO has also provided for an Exit
Transition Cost rider, which allows the Company to recover costs associated with
the transition. As the cost of gas is currently passed through to
customers through a PUCO approved recovery mechanism, the impact of exiting the
merchant function should not have a material impact on Company earnings or
financial condition.
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
the settlement agreement reached in its Vectren North gas rate case. The
order provided for a base rate increase of $16.3 million and a return on equity
(ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate
base of approximately $793 million. The order also provides for the
recovery of $10.6 million of costs through separate cost recovery mechanisms
rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The regulatory
accounting treatment allows for the continuation of the accrual for allowance
for funds used during construction (AFUDC) and the deferral of depreciation
expense after the projects go in service but before they are included in base
rates. To qualify for this treatment, the annual expenditures are limited
to $20 million and the treatment cannot extend beyond four years on each
project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s electric rate case. The order
provided for an approximate $60.8 million electric rate increase to cover the
Company’s cost of system growth, maintenance, safety and reliability. The
order provided for, among other things: recovery of ongoing costs and deferred
costs associated with the MISO; operations and maintenance (O&M) expense
increases related to managing the aging workforce, including the development of
expanded apprenticeship programs and the creation of defined training programs
to ensure proper knowledge transfer, safety and system stability; increased
O&M expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by sharing equally with customers any
profit earned above or below $10.5 million of wholesale power margin; recovery
of and return on the investment in past demand side management programs to help
encourage conservation during peak load periods; timely recovery of the
Company’s investment in certain new electric transmission projects that benefit
the MISO infrastructure; an overall rate of return of 7.32 percent on rate base
of approximately $1,044 million and an allowed ROE of 10.4 percent.
Vectren South Gas Base Rate
Order Received
On August
1, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s gas rate case. The order provided
for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an
overall rate of return of 7.2 percent on rate base of approximately $122
million. The order also provided for the recovery of $2.6 million of
costs through separate cost recovery mechanisms rather than base
rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The regulatory
accounting treatment allows for the continuation of the accrual for allowance
for funds used during construction (AFUDC) and the deferral of depreciation
expense after the projects go in service but before they are included in base
rates. To qualify for this treatment, the annual expenditures are limited
to $3 million and the treatment cannot extend beyond three years on each
project.
With this
order, the Company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission
needs of much of the Midwest and maintains operational control over the
Company’s electric transmission facilities as well as that of other Midwest
utilities. Since April 1, 2005, the Company has been an active participant
in the MISO energy markets, bidding its owned generation into the Day Ahead and
Real Time markets and procuring power for its retail customers at Locational
Marginal Pricing (LMP) as determined by the MISO market.
The
Company is typically in a net sales position with MISO as generation capacity is
in excess of that needed to serve native load and is only occasionally in a net
purchase position. When the Company is a net seller such net revenues are
included in Electric Utility
revenues and when the Company is a net purchaser such net purchases are
included in Cost of fuel and
purchased power. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO day ahead and real-time markets. Net revenues from wholesale
activities included in Electric Utility revenues
totaled $57.6 million in 2008, $39.8 million in 2007 and $29.8 million in
2006.
The
Company also receives transmission revenue that results from other members’ use
of the Company’s transmission system. These revenues are also
included in Electric Utility
revenues. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered/refunded through tracking
mechanisms.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM.
The need
to expend capital for improvements to the regional transmission system, both to
SIGECO’s facilities as well as to those facilities of adjacent utilities, over
the next several years is expected to be significant. The Company
timely recovers its investment in certain new electric transmission projects
that benefit the MISO infrastructure at a FERC approved rate of
return.
One such
project is an interstate 345 kilovolt transmission line that will connect
the Company’s A B Brown Station to a station in Indiana owned by Duke Energy to
the north and to a station in Kentucky owned by Big Rivers Electric Corporation
to the south. Throughout the project, SIGECO is to recover an
approximate 10 percent return, inclusive of the FERC approved equity rate
of return of 12.38 percent, on capital investments through a
rider mechanism which is periodically updated for actual costs incurred.
Of the total investment, which is expected to approximate $70 million, as of
December 31, 2008, the Company has invested approximately $3.1
million. The Company expects this project to be operational
in 2011. At that time, any operating expenses including depreciation
expense are also expected to be recovered through a FERC approved rider
mechanism. Further, the approval allows for recovery of expenditures made
even in the event currently unforeseen difficulties delay or permanently halt
the project.
Impact of Recently Issued
Accounting Guidance
SFAS
157
On
January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements”
(SFAS 157), except as it applies to nonfinancial assets and nonfinancial
liabilities. FSP FAS 157-2 delayed the effective date of SFAS 157 for
all nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value on a recurring basis (at least
annually). This FSP deferred the effective date of Statement 157 for
those items to fiscal years beginning after November 15, 2008.
SFAS 157
defines fair value, establishes a framework for measuring fair value in
generally accepted accounting principles (GAAP), and expands disclosures about
fair value measurements. This statement does not require any new fair
value measurements; however, the standard impacts how other fair value based
GAAP is applied. The partial adoption of SFAS 157 did not have a
material impact on the Company’s financial position, results of operations or
cash flows. Disclosures impacted by SFAS 157 are included in Note 10
to the consolidated financial statements. The adoption of the
remaining components of SFAS 157 on January 1, 2009 is also not expected to be
material on the Company’s financial position, results of operations or cash
flows.
SFAS
159
Also on
January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115” (SFAS 159). SFAS 159 permits entities to choose to
measure many financial instruments and certain other items at fair
value. The Company did not choose to apply the option provided in
SFAS 159 to any of its eligible items; therefore, its adoption did not have any
impact on the Company’s financial statements or results of
operations.
SFAS
141 (Revised 2007)
In
December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS
141R). SFAS 141R establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141R applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. SFAS 141R applies prospectively to
business combinations with an acquisition date on or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. Early adoption is not permitted. The Company will adopt
SFAS 141R on January 1, 2009, and because the provisions of this standard are
applied prospectively, the impact to the Company cannot be determined until the
transactions occur.
SFAS
161
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS
161). SFAS 161 enhances the current disclosures under SFAS 133 and
requires that objectives for using derivative instruments be disclosed in terms
of underlying risk and accounting designation in order to better convey the
purpose of derivative use in terms of the risks that the entity is intending to
manage. Entities are required to provide enhanced disclosures about
(a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. Tabular disclosure of fair value amounts and gains and
losses on derivative instruments and related hedged items is
required. SFAS 161 is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
adoption encouraged. The Company will adopt SFAS 161 on January 1,
2009, and the impact is not expected to be material to the Company’s financial
position or results of operations.
SFAS
162
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of
accounting principles and the framework for selecting principles used in the
preparation of financial statements. SFAS No. 162 is effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity
with Generally Accepted Accounting Principles”. The implementation of this
standard will not have a material impact on its financial position and results
of operations.
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 impairments
tests. The Company makes other estimates, in the course of accounting
for unbilled revenue and the effects of regulation and intercompany allocations
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, among others. Actual results could differ from these
estimates.
Goodwill
The
Company performs an annual impairment analysis of its goodwill, all 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 11 to the consolidated
financial statements to be the reporting unit. An impairment test
requires that a reporting unit’s fair value be estimated. The Company
used a discounted cash flow model to estimate the fair value of its Gas Utility
Services operating segment, and that estimated fair value was compared to its
carrying amount, including goodwill. The estimated fair value was in
excess of the carrying amount in 2008, 2007, and 2006 and therefore resulted in
no impairment.
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.
Intercompany
Allocations
Support
Services
Vectren
provides corporate, general, and administrative services to the Company and
allocates costs to the Company, including costs for share-based compensation and
for pension and other postretirement benefits that are not directly charged to
subsidiaries. These costs have been allocated using various
allocators, including number of employees, number of customers, and/or the level
of payroll, revenue contribution, and capital
expenditures. Allocations are at cost. Management believes
that the allocation methodology is reasonable and approximates the costs that
would have been incurred had the Company secured those services on a stand-alone
basis. The allocation methodology is not subject to near term
changes.
Pension and Other
Postretirement Obligations
Vectren
satisfies the future funding requirements of its pension and other
postretirement plans and the payment of benefits from general corporate
assets. An allocation of expense is determined, comprised of only
service cost and interest on that service cost, by subsidiary based on headcount
at each measurement date. Vectren has historically measured its
obligations annually on September 30. However, in 2008, Vectren
measured these obligations on December 31 in accordance with SFAS No. 158,
“Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS
158). These costs are directly charged to individual
subsidiaries. Other components of costs (such as interest cost and
asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Neither plan assets nor the
ending liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. Management
believes these direct charges when combined with benefit-related corporate
charges discussed in “support services” above approximate costs that would have
been incurred if the Company accounted for benefit plans on a stand-alone
basis.
Vectren
estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other inputs, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of pension and postretirement plans. Vectren
used the following weighted average assumptions to develop 2008 periodic benefit
cost: a discount rate of 6.25 percent, an expected return on plan
assets of 8.25 percent, a rate of compensation increase of 3.75 percent, and an
inflation assumption of 3.5 percent. In 2008, the Company increased
the discount rate from 5.85 percent, which was used to measure 2007 periodic
cost due to an increase in benchmark interest rates. Due to the
recent and significant decline in asset values, retirement plan costs are
expected to be higher in 2009 and in subsequent years. Management
currently estimates a pension and postretirement cost of approximately $14 to
$16 million in 2009 depending on funding levels, compared to approximately $11
million in 2008. Future changes in health care costs, work force
demographics, interest rates, asset values or plan changes could significantly
affect the estimated cost of these future benefits. Management
estimates that a 50 basis point decrease in the discount rate would generally
increase periodic benefit cost by approximately $1.7 million.
Unbilled
Revenues
To more
closely match revenues and expenses, the Company records revenues for all gas
and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the
month to allocate unbilled units by customer class. Those allocated
units are multiplied by rates in effect during the month to calculate unbilled
revenue at balance sheet dates.
Regulation
At each
reporting date, the Company reviews current regulatory trends in the markets in
which it operates. This review involves judgment and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS
71). Based on the Company’s current review, it believes its
regulatory assets are probable of recovery. If all or part of the
Company's operations cease to meet the criteria of SFAS 71, a write off of
related regulatory assets and liabilities could be required. In
addition, the Company would be required to determine any impairment to the
carrying value of its utility plant and other regulated assets and
liabilities. In the unlikely event of a change in the current
regulatory environment, such write-offs and impairment charges could be
significant.
Financial
Condition
Utility
Holdings funds the short-term and long-term financing needs of utility
operations. Vectren does not guarantee Utility Holdings’
debt. Utility Holdings’ outstanding long-term and short-term
borrowing arrangements are jointly and severally guaranteed by Indiana Gas,
SIGECO, and VEDO. The guarantees are full and unconditional and joint
and several, and Utility Holdings has no subsidiaries other than the subsidiary
guarantors. Information about the subsidiary guarantors as a group is
included in Note 14 to the consolidated financial statements. Utility
Holdings’ long-term and short-term obligations outstanding at December 31, 2008,
approximated $823 million and $192 million,
respectively. Additionally, prior to Utility Holdings’ formation,
Indiana Gas and SIGECO funded their operations separately, and therefore, have
long-term debt outstanding funded solely by their operations. Utility
Holdings’ operations have historically been the primary source for Vectren’s
common stock dividends.
The
credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas,
at December 31, 2008, are A-/Baa1 as rated by Standard and Poor's Ratings
Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s),
respectively. The credit ratings on SIGECO's secured debt are
A/A3. Utility Holdings’ commercial paper has a credit rating of
A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s
is stable. A security rating is not a recommendation to buy, sell, or
hold securities. The rating is subject to revision or withdrawal at
any time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade
rating is BBB- and Baa3, respectively.
The
Company’s consolidated equity capitalization objective is 45-55 percent of
long-term capitalization. This objective may have varied, and will
vary, depending on particular business opportunities, capital spending
requirements, execution of long-term financing plans and seasonal factors that
affect the Company’s operations. The Company’s equity component was
52 percent and 51 percent of long-term capitalization at December 31, 2008
and 2007, respectively. Long-term capitalization includes
long-term debt, including current maturities and debt subject to tender, as well
as common shareholder’s equity.
As of
December 31, 2008, the Company was in compliance with all financial
covenants.
Available
Liquidity in Current Credit Conditions
As noted
below, in 2008 the Company completed permanent financing transactions, including
the issuance of $125 million in long-term debt; receiving a $125 million capital
contribution from Vectren. These transactions have increased the
level of unutilized short-term borrowing capacity. This unutilized
short-term debt capacity, when coupled with expected internally generated funds
and any additional long-term financings undertaken, should provide sufficient
liquidity over the next twelve to twenty four months to fund anticipated capital
expenditures, investments, and debt security redemptions.
Regarding
debt redemptions, there are none in 2009 and 2010. However, holders
of certain debt instruments have the one-time option to put them to the
Company. Debt subject to these put provisions total $80 million in
2009 and $10 million in 2010.
The
Company continues to develop plans to issue additional long-term debt over the
next twelve to twenty four months, assuming its A-/Baa1 investment grade credit
ratings will allow it to access the capital markets, as the need
arises. However, while debt markets have improved somewhat, such
long-term debt issued during this period could be more expensive than in recent
history. This permanent financing would reduce reliance on unutilized
short-term capacity.
Consolidated Short-Term
Borrowing Arrangements
At
December 31, 2008, the Company had $520 million of short-term borrowing
capacity, of which approximately $328 million was available. Of
the $520 million in capacity, $515 million is available through November,
2010.
Historically,
the Company has funded its short-term borrowing needs through the commercial
paper market. In 2008, the Company’s access to longer term commercial
paper was significantly reduced as a result of the continued turmoil and
volatility in the financial markets. As a result, the Company has met
working capital requirements through a combination of A2/P2 commercial paper
issuances and draws on its $515 million commercial paper back-up credit
facilities. In addition, the Company increased its cash
investments by approximately $40 million during the fourth quarter of
2008. This cash position was liquidated in January 2009 based upon
improvements in the short-term debt and commercial paper markets; and therefore,
resulted in an increase to the available short-term debt capacity.
Proceeds from Stock
Plans
Vectren
may periodically issue new common shares to satisfy dividend reinvestment plan,
stock option plan, and other employee benefit plan requirements and contribute
those proceeds to Utility Holdings. New issuances contributed to
Utility Holdings added additional liquidity of $5.3 million in
2007. In 2009, new issuances required to meet these various plan
requirements are estimated to be approximately $6 million, and such amount is
expected to be contributed to Utility Holdings.
Potential
Uses of Liquidity
Planned Capital
Expenditures
The
timing and amount of planned capital expenditures, including contractual
purchase commitments discussed below, for the five-year period 2009 - 2013 are
estimated as follows (in millions): $250 in 2009, $265 in 2010, $255
in 2011, $270 in 2012, and $245 in 2013.
Pension and Postretirement
Funding Obligations
Vectren’s
pension plan asset values were approximately $151 million at December 31, 2008,
compared to asset values as of December 31, 2007 of approximately $212 million,
and since December 31, 2008, market values have remained volatile and have
experienced further declines. Asset values for qualified plans as of
December 31, 2008 are approximately 61 percent of the projected benefit
obligation. Vectren management currently estimates that the qualified pension
plans may require Company contributions of approximately $25 to $30 million in
2009 and a lesser level in 2010, a portion of which may be funded by Utility
Holdings. During 2008, Vectren made contributions of
approximately $12 million, none of which were funded by Utility
Holdings.
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2008:
|
Total
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
||||||||||||||||||||||
|
Long-term debt (1)
|
$ | 1,148.3 | $ | - | $ | - | $ | 250.0 | $ | - | $ | 105.0 | $ | 793.3 | ||||||||||||||
|
Short-term
debt
|
191.9 | 191.9 | - | - | - | - | - | |||||||||||||||||||||
|
Long-term
debt interest commitments
|
1,051.0 | 70.6 | 70.6 | 69.2 | 54.0 | 51.7 | 734.9 | |||||||||||||||||||||
|
Plant & commodity purchase commitments (2)
|
6.8 | 6.8 | - | - | - | - | - | |||||||||||||||||||||
|
Operating
leases
|
2.3 | 1.0 | 0.6 | 0.3 | 0.2 | 0.2 | - | |||||||||||||||||||||
|
Total (3)
|
$ | 2,400.3 | $ | 270.3 | $ | 71.2 | $ | 319.5 | $ | 54.2 | $ | 156.9 | $ | 1,528.2 | ||||||||||||||
|
(1)
|
Certain
long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions
allow holders the one-time option to put debt back to the Company at face
value or the Company to call debt at face value or at a
premium. Long-term debt subject to tender during the years
following 2008 (in millions) is $80.0 in 2009, $10.0 in 2010, $30.0 in
2011, zero in 2012 and thereafter.
|
|
(2)
|
The
settlement period of these utility and nonutility plant obligations is
estimated.
|
|
(3)
|
The
Company has other long-term liabilities that total approximately $105
million. This amount is comprised of the
following: deferred compensation and share-based compensation
$27 million, asset retirement obligations $25 million, pension obligations
$19 million, postretirement obligations $19 million, investment tax
credits $7 million, environmental remediation $6 million, and other
obligations including unrecognized tax benefits totaling $2
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, coal, and electricity as well as certain transportation
and storage rights. Costs arising from these commitments, while
significant, are pass-through costs, generally collected dollar-for-dollar from
retail customers through regulator-approved cost recovery
mechanisms. Because of the pass through nature of these costs and
their insignificant impact to earnings, they have not been included in the
listing of contractual obligations.
Off Balance Sheet
Arrangements
As of
December 31, 2008, the Company does not have any material off balance sheet
arrangements.
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 $435.0 million in 2008,
compared to $232.2 million in 2007 and $286.1 million in 2006.
In 2008
cash flow from operating activities increased $202.8 million compared to
2007. Working capital changes generated cash of $71.5 million in 2008
compared to cash used of $33.7 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. Higher levels of deferred taxes
due primarily to federal stimulus plans authorizing bonus depreciation on
qualifying capital expenditures increased cash flow approximately $40.3
million. The remaining increase in operating cash flow is primarily
due to the cash collection of previously deferred regulatory assets and higher
earnings and depreciation.
While net
income increased substantially in 2007 compared to 2006, cash flow from
operating activities decreased $53.9 million. The decrease was
primarily a result of changes in working capital accounts. Working
capital changes used cash of $33.7 million in 2007 compared to cash generated of
$68.7 million in 2006. These decreases were partially offset by the
higher earnings in 2007 as well as increased deferred taxes and
depreciation.
Financing Cash
Flow
Although
working capital requirements are generally funded by cash flow from operations,
the Company uses short-term borrowings to supplement working capital needs when
accounts receivable balances are at their highest and gas storage is
refilled. Additionally, short-term borrowings are required for
capital projects and investments until they are financed on a long-term
basis.
Net cash
flow used for financing activities was $85.9 million in
2008. The increased cash used for financing activities during
2008 compared to 2007 is reflective the increased operating cash flows used to
repay short-term borrowings and is also reflective of the impact of completed
long-term financing transactions, including the issuance of long term debt and a
capital contribution from Vectren. In 2007 compared to 2006,
financing activities reflect short-term and long-term debt proceeds and stock
option proceeds offset by debt payments and dividends.
In 2008,
Utility Holdings issued $125 million of senior unsecured securities and received
a $124.8 million capital contribution from Vectren. Those proceeds
were used to refinance certain capital projects originally financed with
short-term borrowings. Also, during the first quarter of 2008, the
Company mitigated its exposure to auction rate debt markets. In 2006,
Utility Holdings issued $100 million of senior unsecured securities and used
those proceeds to retire higher coupon long-term debt. These
transactions are more fully described below.
Capital
Contribution from Vectren
On June
27, 2008, Vectren physically settled an equity forward agreement associated with
a 2007 public offering of its common stock. Vectren transferred net
proceeds of approximately $124.8 million 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
Shareholder’s Equity and are presented in the Statement of Cash Flows as a
financing activity.
Additional
Capital Contributions
In
addition to the $124.8 million capital contribution above, during the years
ended December 31, 2008, 2007 and 2006, the Company has cumulatively received
additional capital of $25.3 million from Vectren. Of that total, $20
million was funded by Vectren’s nonutility operations, and $5.3 million was
funded by new share issues from Vectren’s dividend reinvestment
plan.
Utility
Holdings 2008 Debt Issuance
In March
2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured
notes due April 1, 2039 (2039 Notes) at par. The 2039 Notes are
guaranteed by Utility Holdings’ three public utilities: SIGECO,
Indiana Gas, and VEDO. These guarantees are full and unconditional
and joint and several.
The 2039
Notes have no sinking fund requirements, and interest payments are due
monthly. The notes may be called by Utility Holdings, in whole or in
part, at any time on or after April 1, 2013, at 100 percent of principal amount
plus accrued interest. During 2007, Utility Holdings entered into
several interest rate hedges with an $80 million notional
amount. Upon issuance of the notes, these instruments were settled
resulting in the payment of approximately $9.6 million, which was recorded as a
Regulatory asset
pursuant to existing regulatory orders. The value paid is being
amortized as an increase to interest expense over the life of the
issue. The proceeds from the sale of the 2039 Notes less settlement
of the hedging arrangements and payments of issuance costs amounted to
approximately $111.1 million.
Auction
Rate Securities
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt had a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate was to reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation (Ambac).
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax-exempt auction rate mode long-term debt, including the $17
million issued in December 2007, of its plans to convert that debt from its
current auction rate mode into a daily interest rate mode. In March
2008, the debt was tendered at 100 percent of the principal amount plus accrued
interest. During March 2008, SIGECO remarketed approximately $61.8
million of these instruments at interest rates that are fixed to maturity,
receiving proceeds, net of issuance costs, of approximately $60.0
million. The terms are $22.6 million at 5.15 percent due in 2023,
$22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due
in 2041. The remaining $41.3 million continues to be held in treasury
and is expected to be remarketed in 2009.
Utility Holdings 2006 Debt
Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95 percent senior
unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes
were priced at par. The 2036 Notes are guaranteed by Utility
Holdings’ three public utilities: SIGECO, Indiana Gas, and
VEDO. These guarantees are full and unconditional and joint and
several. These notes, as well as the timely payment of principal and
interest, are insured by a financial guaranty insurance policy by Financial
Guaranty Insurance Company (FGIC).
The 2036
Notes have no sinking fund requirements, and interest payments are due
quarterly. The notes may be called by Utility Holdings, in whole or
in part, at any time on or after October 1, 2011, at 100 percent of principal
amount plus accrued interest. During the first and second quarters of
2006, Utility Holdings entered into several interest rate hedges with a $100
million notional amount. Upon issuance of the notes, these
instruments were settled resulting in the payment of approximately $3.3 million,
which was recorded as a Regulatory asset pursuant to
existing regulatory orders. The value paid is being amortized as an
increase to interest expense over the life of the issue maturing October
2036.
The net
proceeds from the sale of the 2036 Notes and settlement of the hedging
arrangements totaled approximately $92.8 million.
Utility
Holdings and Indiana Gas Debt Calls
In 2006,
the Company called at par $100.0 million of Utility Holdings senior unsecured
notes originally due in 2031. The note had a stated interest rate of
7.25 percent.
Other
Financing Transactions
Other
Company debt totaling $6.5 million in 2007 was retired as
scheduled.
Long-Term
Debt Put and Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. Other than certain instruments that
can be put to the company upon the death of the holder (death puts), these put
or call provisions are not triggered by specific events, but are based upon
dates stated in the note agreements. During 2008, the Company repaid
approximately $1.6 million related to death puts. In 2007 and 2006,
no debt was put to the Company. Debt which may be put to the Company
for reasons other than a death during the years following 2008 (in millions) is
$80.0 in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and
thereafter. Debt that may be put to the Company within one year is
classified as Long-term debt
subject to tender in current liabilities.
Investing Cash
Flow
Cash flow
required for investing activities was $308.3 million in 2008, $303.3 million in
2007, and $249.9 million in 2006. Capital expenditures are the
primary component of investing activities and totaled $306.3 million in 2008,
compared to $302.5 million in 2007 and $250.0 million in 2006. The
year ended December 31, 2008 includes increased capital expenditures for
environmental compliance equipment, compared to 2007. The year ended
December 31, 2007 also includes expenditures for environmental compliance
equipment as well as increased spending for electric transmission and a new gas
line serving a Honda plant in the Vectren North service territory, compared to
2006.
Forward-Looking
Information
A
“safe harbor” for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The
Reform Act of 1995 was adopted to encourage such forward-looking statements
without the threat of litigation, provided those statements are identified as
forward-looking and are accompanied by meaningful cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Certain matters
described in Management’s Discussion and Analysis of Results of Operations and
Financial Condition are forward-looking statements. Such statements
are based on management’s beliefs, as well as assumptions made by and
information currently available to management. When used in this
filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”,
“objective”, “projection”, “forecast”, “goal” and similar expressions are
intended to identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause the Company’s actual
results to differ materially from those contemplated in any forward-looking
statements include, among others, the following:
|
·
|
Factors
affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
transportation and storage costs, or availability due to higher demand,
shortages, transportation problems or other developments; environmental or
pipeline incidents; transmission or distribution incidents; unanticipated
changes to electric energy supply costs, or availability due to demand,
shortages, transmission problems or other developments; or electric
transmission or gas pipeline system
constraints.
|
|
·
|
Increased
competition in the energy industry, including the effects of industry
restructuring and unbundling.
|
|
·
|
Regulatory
factors such as unanticipated changes in rate-setting policies or
procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate
increases.
|
|
·
|
Financial,
regulatory or accounting principles or policies imposed by the Financial
Accounting Standards Board; the Securities and Exchange Commission; the
Federal Energy Regulatory Commission; state public utility commissions;
state entities which regulate electric and natural gas transmission and
distribution, natural gas gathering and processing, electric power supply;
and similar entities with regulatory
oversight.
|
|
·
|
Economic
conditions including the effects of an economic downturn, inflation rates,
commodity prices, and monetary
fluctuations.
|
|
·
|
Economic
conditions surrounding the current recession, which may be more prolonged
and more severe than cyclical downturns, including significantly lower
levels of economic activity; uncertainty regarding energy prices and the
capital and commodity markets; decreases in demand for natural gas, and
electricity; impacts on both gas and electric large customers;
lower residential and commercial customer counts; and higher operating
expenses.
|
|
·
|
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.
|
|
·
|
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
performance of projects undertaken by Vectren’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.
|
The
Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK
The
Company is exposed to various business risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures
are monitored and managed by the Company as an integral part of its overall risk
management program. The Company’s risk management program includes,
among other things, the use of derivatives. The Company may also
execute derivative contracts in the normal course of operations while buying and
selling commodities to be used in operations and optimizing its generation
assets.
|
The
Company has in place a risk management committee that consists of senior
management as well as financial and operational management. The
committee is actively involved in identifying risks as well as reviewing
and authorizing risk mitigation
strategies.
|
Commodity
Price Risk
Regulated
Operations
The
Company’s regulated operations have limited exposure to commodity price risk for
transactions involving purchases and sales of natural gas, coal and purchased
power for the benefit of retail customers due to current Indiana and Ohio
regulations, which subject to compliance with those regulations, allow for
recovery of the cost of such purchases through natural gas and fuel cost
adjustment mechanisms. Constructive regulatory orders, such as those
authorizing lost margin recovery, other innovative rate designs, and recovery of
unaccounted for gas and other gas related expenses, also mitigate the effect
volatile gas costs may have on the Company’s financial condition.
Although
the Company’s regulated operations are exposed to limited commodity price risk,
volatile natural gas prices have other effects such as higher working capital
requirements, higher interest costs, and some level of price-sensitivity in
volumes sold or delivered. The Company manages these risks by
executing derivative contracts that hedge the price of forecasted natural gas
purchases. These contracts are subject to regulation which allows for
reasonable and prudent hedging costs to be recovered through
rates. Therefore, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
Wholesale Power
Marketing
The
Company’s wholesale power marketing activities undertake strategies to optimize
electric generating capacity beyond that needed for native load. In
recent years, the primary strategy involves the sale of excess generation into
the MISO Day Ahead and Real-time markets. As part of these
strategies, the Company may also from time to time execute energy contracts that
commit the Company to purchase and sell electricity in the
future. Commodity price risk results from forward positions that
commit the Company to deliver electricity. The Company mitigates
price risk exposure with planned unutilized generation capability and
occasionally offsetting forward purchase contracts. The Company
accounts for any energy contracts that are derivatives at fair value with the
offset marked to market through earnings. No market sensitive
derivative positions were outstanding on December 31, 2008 and
2007.
For
retail sales of electricity, the Company receives the majority of its NOx and
SO2
allowances at zero cost through an allocation process. Based
on arrangements with regulators, wholesale operations can purchase allowances
from retail operations at current market values, the value of which is
distributed back to retail customers through a MISO cost recovery tracking
mechanism. Wholesale operations are therefore at risk for the cost of
allowances, which for the recent past have been volatile. The Company
manages this risk by purchasing allowances from retail operations and other
third parties in advance of usage creating an intangible asset. In
the past, the Company has also used derivative financial instruments to hedge
this risk, but no such derivative instruments were outstanding at December 31,
2008 or 2007.
Interest
Rate Risk
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on interest
expense. The Company manages this risk by allowing an annual average
of 20 percent and 30 percent of its total debt to be exposed to variable rate
volatility. However, this targeted range may be exceeded during the
seasonal increases in short-term borrowing. To manage this exposure,
the Company may use derivative financial instruments.
Market
risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2008 and 2007, the weighted average
combined borrowings under these arrangements approximated $278 million and $340
million, respectively. At December 31, 2008 and 2007, combined
borrowings under these arrangements were $192 million and $489 million,
respectively. Based upon average borrowing rates under these
facilities during the years ended December 31, 2008 and 2007, an increase of 100
basis points (one percentage point) in the rates would have increased interest
expense by $2.8 million and $3.4 million, respectively.
Other
Risks
By using
financial instruments to manage risk, the Company exposes itself to
counter-party credit risk and market risk. The Company manages
exposure to counter-party credit risk by entering into contracts with companies
that can be reasonably expected to fully perform under the terms of the
contract. Counter-party credit risk is monitored regularly and
positions are adjusted appropriately to manage risk. Further, tools
such as netting arrangements and requests for collateral are also used to manage
credit risk. Market risk is the adverse effect on the value of a
financial instrument that results from a change in commodity prices or interest
rates. The Company attempts to manage exposure to market risk
associated with commodity contracts and interest rates by establishing
parameters and monitoring those parameters that limit the types and degree of
market risk that may be undertaken.
The
Company’s customer receivables from gas and electric sales and gas
transportation services are primarily derived from residential, commercial, and
industrial customers located in Indiana and west central Ohio. The
Company manages credit risk associated with its receivables by continually
reviewing creditworthiness and requests cash deposits or refunds cash deposits
based on that review. Credit risk associated with certain investments
is also managed by a review of creditworthiness and receipt of
collateral. In addition, credit risk is mitigated by regulatory
orders that allow recovery of all bad debt expense in Ohio and the gas cost
portion of bad debt expense in Indiana based on historical
experience.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA
MANAGEMENT’S RESPONSIBILITY
FOR THE FINANCIAL STATEMENTS
Vectren
Utility Holdings, Inc.’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 shareholder’s equity, and related
footnotes contained herein.
These
consolidated financial statements were prepared in conformity with accounting
principles generally accepted in the United States and follow accounting
policies and principles applicable to regulated public utilities. The
integrity and objectivity of these consolidated financial statements, including
required estimates and judgments, is the responsibility of
management.
These
consolidated financial statements are also subject to an evaluation of internal
control over financial reporting conducted under the supervision and with the
participation of management, including the Chief Executive Officer and Chief
Financial Officer. Based on that evaluation, conducted under the
framework in Internal Control
— Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission, the Company concluded that its
internal control over financial reporting was effective as of December 31,
2008. Management certified this in its Sarbanes Oxley Section 302
certifications, which are attached as exhibits to this 2008 Form
10-K.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Shareholder and Board of Directors of Vectren Utility Holdings,
Inc.:
We have
audited the accompanying consolidated balance sheets of Vectren Utility
Holdings, Inc. and subsidiaries (the “Company”) as of December 31, 2008
and 2007, and the related consolidated statements of income, common
shareholder’s equity and cash flows for each of the three years in the period
ended December 31, 2008. Our audits also included the financial statement
schedule included in the Index at Item 15. These financial statements and
financial statement schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, 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 Utility Holdings, Inc. and
subsidiaries as of December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2008, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
/s/
DELOITTE & TOUCHE LLP
Indianapolis,
Indiana
February
18, 2009
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
|
|
CONSOLIDATED
BALANCE SHEETS
|
(In
millions)
|
At December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
& cash equivalents
|
$ | 52.5 | $ | 11.7 | ||||
|
Accounts
receivable - less reserves of $4.5 &
|
||||||||
|
$2.7,
respectively
|
164.0 | 137.1 | ||||||
|
Receivables
due from other Vectren companies
|
4.7 | 17.9 | ||||||
|
Accrued
unbilled revenues
|
167.2 | 140.6 | ||||||
|
Inventories
|
84.6 | 134.9 | ||||||
|
Recoverable
fuel & natural gas costs
|
3.1 | - | ||||||
|
Prepayments
& other current assets
|
103.1 | 93.3 | ||||||
|
Total
current assets
|
579.2 | 535.5 | ||||||
|
Utility
Plant
|
||||||||
|
Original
cost
|
4,335.3 | 4,062.9 | ||||||
|
Less: accumulated
depreciation & amortization
|
1,615.0 | 1,523.2 | ||||||
|
Net
utility plant
|
2,720.3 | 2,539.7 | ||||||
|
Investments
in unconsolidated affiliates
|
0.2 | 0.2 | ||||||
|
Other
investments
|
24.1 | 24.7 | ||||||
|
Nonutility
property - net
|
182.4 | 176.2 | ||||||
|
Goodwill
- net
|
205.0 | 205.0 | ||||||
|
Regulatory
assets
|
115.7 | 151.7 | ||||||
|
Other
assets
|
11.2 | 10.7 | ||||||
|
TOTAL
ASSETS
|
$ | 3,838.1 | $ | 3,643.7 | ||||
The accompanying notes are an
integral part of these consolidated financial statements.
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
At
December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
LIABILITIES & SHAREHOLDER'S
EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable
|
$ | 212.5 | $ | 138.7 | ||||
|
Accounts
payable to affiliated companies
|
72.8 | 66.9 | ||||||
|
Payables
to other Vectren companies
|
69.0 | 34.2 | ||||||
|
Refundable
fuel & natural gas costs
|
4.1 | 27.2 | ||||||
|
Accrued
liabilities
|
147.7 | 138.9 | ||||||
|
Short-term
borrowings
|
191.9 | 385.9 | ||||||
|
Long-term
debt subject to tender
|
80.0 | - | ||||||
|
Total
current liabilities
|
778.0 | 791.8 | ||||||
|
Long-Term
Debt - Net of Current Maturities &
|
||||||||
|
Debt
Subject to Tender
|
1,065.1 | 1,062.6 | ||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||
|
Deferred
income taxes
|
332.1 | 286.9 | ||||||
|
Regulatory
liabilities
|
315.1 | 307.2 | ||||||
|
Deferred
credits & other liabilities
|
104.9 | 104.8 | ||||||
|
Total
deferred credits & other liabilities
|
752.1 | 698.9 | ||||||
|
Commitments
& Contingencies (Notes 7 - 9)
|
||||||||
|
Common
Shareholder's Equity
|
||||||||
|
Common
stock (no par value)
|
763.0 | 638.2 | ||||||
|
Retained
earnings
|
479.8 | 451.9 | ||||||
|
Accumulated
other comprehensive income
|
0.1 | 0.3 | ||||||
|
Total
common shareholder's equity
|
1,242.9 | 1,090.4 | ||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,838.1 | $ | 3,643.7 | ||||
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF INCOME
(In
millions)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Electric
utility
|
524.2 | 487.9 | 422.2 | |||||||||
|
Other
|
1.8 | 1.7 | 1.8 | |||||||||
|
Total
operating revenues
|
1,958.7 | 1,759.0 | 1,656.5 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
983.1 | 847.2 | 841.5 | |||||||||
|
Cost
of fuel & purchased power
|
182.9 | 174.8 | 151.5 | |||||||||
|
Other
operating
|
300.3 | 266.1 | 239.0 | |||||||||
|
Depreciation
& amortization
|
165.5 | 158.4 | 151.3 | |||||||||
|
Taxes
other than income taxes
|
72.3 | 68.1 | 64.2 | |||||||||
|
Total
operating expenses
|
1,704.1 | 1,514.6 | 1,447.5 | |||||||||
|
OPERATING
INCOME
|
254.6 | 244.4 | 209.0 | |||||||||
|
Other
income - net
|
4.0 | 9.4 | 7.6 | |||||||||
|
Interest
expense
|
79.9 | 80.6 | 77.5 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
178.7 | 173.2 | 139.1 | |||||||||
|
Income
taxes
|
67.6 | 66.7 | 47.7 | |||||||||
|
NET
INCOME
|
$ | 111.1 | $ | 106.5 | $ | 91.4 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net
income
|
$ | 111.1 | $ | 106.5 | $ | 91.4 | ||||||
|
Adjustments
to reconcile net income to cash from operating activities:
|
||||||||||||
|
Depreciation
& amortization
|
165.5 | 158.4 | 151.3 | |||||||||
|
Deferred income
taxes & investment tax credits
|
54.7 | 14.4 | (6.4 | ) | ||||||||
|
Expense
portion of pension & postretirement periodic benefit
cost
|
2.6 | 4.1 | 4.2 | |||||||||
|
Provision for
uncollectible accounts
|
15.8 | 15.0 | 13.6 | |||||||||
|
Other
non-cash (income) expense - net
|
15.7 | 7.6 | (2.4 | ) | ||||||||
|
Changes
in working capital accounts:
|
||||||||||||
|
Accounts
receivable, including to Vectren companies
|
||||||||||||
|
& accrued
unbilled revenue
|
(56.1 | ) | (54.1 | ) | 115.3 | |||||||
|
Inventories
|
46.8 | 7.0 | (15.7 | ) | ||||||||
|
Recoverable/refundable fuel
& natural gas costs
|
(26.2 | ) | (6.3 | ) | 41.3 | |||||||
|
Prepayments &
other current assets
|
(13.4 | ) | 4.0 | 16.7 | ||||||||
|
Accounts payable,
including to Vectren companies
|
||||||||||||
|
& affiliated
companies
|
96.2 | 14.6 | (74.7 | ) | ||||||||
|
Accrued
liabilities
|
24.2 | 1.1 | (14.2 | ) | ||||||||
|
Changes
in noncurrent assets
|
20.6 | (22.3 | ) | (27.2 | ) | |||||||
|
Changes
in noncurrent liabilities
|
(22.5 | ) | (17.8 | ) | (7.1 | ) | ||||||
|
Net cash flows from
operating activities
|
435.0 | 232.2 | 286.1 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
171.1 | 16.3 | 92.8 | |||||||||
|
Additional
capital contribution
|
124.8 | 5.3 | 20.0 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Dividends to
parent
|
(83.2 | ) | (76.6 | ) | (75.4 | ) | ||||||
|
Retirement of
long-term debt
|
(104.6 | ) | (6.5 | ) | (100.0 | ) | ||||||
|
Net
change in short-term borrowings, including from other
|
||||||||||||
|
Vectren
companies
|
(194.0 | ) | 115.8 | 43.2 | ||||||||
|
Net cash flows from
financing activities
|
(85.9 | ) | 54.3 | (19.4 | ) | |||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds from other investing
activities
|
2.5 | 1.0 | 0.1 | |||||||||
|
Requirements for:
|
||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(306.3 | ) | (302.5 | ) | (250.0 | ) | ||||||
|
Other
investments
|
(4.5 | ) | (1.8 | ) | - | |||||||
|
Net cash
flows from investing activities
|
(308.3 | ) | (303.3 | ) | (249.9 | ) | ||||||
|
Net
change in cash & cash equivalents
|
40.8 | (16.8 | ) | 16.8 | ||||||||
|
Cash
& cash equivalents at beginning of period
|
11.7 | 28.5 | 11.7 | |||||||||
|
Cash
& cash equivalents at end of period
|
$ | 52.5 | $ | 11.7 | $ | 28.5 | ||||||
|
Cash
paid during the year for:
|
||||||||||||
| Interest | $ | 74.9 | 77.1 | 75.2 | ||||||||
|
Income
taxes
|
14.8 | 44.9 | 49.8 | |||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(In
millions)
|
Accumulated
|
||||||||||||||||
|
Other
|
||||||||||||||||
|
Common
|
Retained
|
Comprehensive
|
||||||||||||||
|
Stock
|
Earnings
|
Income
(Loss)
|
Total
|
|||||||||||||
|
Balance
at January 1, 2006
|
$ | 612.9 | $ | 406.9 | $ | 4.0 | $ | 1,023.8 | ||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
91.4 | 91.4 | ||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
Unrealized losses - net
of $1.5 million in tax
|
(2.1 | ) | (2.1 | ) | ||||||||||||
|
Reclassification to net income - net of $0.7 million in
tax
|
(1.0 | ) | (1.0 | ) | ||||||||||||
|
Total
comprehensive income
|
88.3 | |||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
20.0 | 20.0 | ||||||||||||||
|
Dividends
|
(75.4 | ) | (75.4 | ) | ||||||||||||
|
Balance
at December 31, 2006
|
632.9 | 422.9 | 0.9 | 1,056.7 | ||||||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
106.5 | 106.5 | ||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
Unrealized
gain - net of $0.1 million in tax
|
0.1 | 0.1 | ||||||||||||||
|
Reclassification to net income - net of $0.4 million in
tax
|
(0.7 | ) | (0.7 | ) | ||||||||||||
|
Total
comprehensive income
|
105.9 | |||||||||||||||
|
Adoption
of FIN 48
|
(0.9 | ) | (0.9 | ) | ||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
5.3 | 5.3 | ||||||||||||||
|
Dividends
|
(76.6 | ) | (76.6 | ) | ||||||||||||
|
Balance
at December 31, 2007
|
638.2 | 451.9 | 0.3 | 1,090.4 | ||||||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
111.1 | 111.1 | ||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
Reclassification to net income - net of $0.2 million in
tax
|
(0.2 | ) | (0.2 | ) | ||||||||||||
|
Total
comprehensive income
|
110.9 | |||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
124.8 | 124.8 | ||||||||||||||
|
Dividends
|
(83.2 | ) | (83.2 | ) | ||||||||||||
|
Balance
at December 31, 2008
|
$ | 763.0 | $ | 479.8 | $ | 0.1 | $ | 1,242.9 | ||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
UTILITY HOLDINGS INC. AND SUBSIDIARY COMPANIES
NOTES
TO THE CONSOLIDATED FINANCIAL STATEMENTS
|
1.
|
Organization
and Nature of Operations
|
Vectren
Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana
corporation, was formed on March 31, 2000, to serve as the intermediate holding
company for Vectren Corporation’s (Vectren) three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North),
Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the
Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has
other assets that provide information technology and other services to the three
utilities. Vectren, an Indiana corporation, is an energy holding
company headquartered in Evansville, Indiana, and was organized on June 10,
1999. Both Vectren and Utility Holdings are holding companies as
defined by the Energy Policy Act of 2005 (Energy Act).
Indiana
Gas provides energy delivery services to over 568,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 111,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and
SIGECO generally do business as Vectren Energy Delivery of
Indiana. The Ohio operations provide energy delivery services to
approximately 317,000 natural gas customers located near Dayton in west central
Ohio. The Ohio operations are owned as a tenancy in common by Vectren
Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility
Holdings (53 percent ownership), and Indiana Gas (47 percent
ownership). The Ohio operations generally do business as Vectren
Energy Delivery of Ohio.
|
2.
|
Summary
of Significant Accounting Policies
|
|
A.
|
Principles
of Consolidation
|
The
consolidated financial statements include the accounts of the Company and its
wholly owned and majority owned subsidiaries, after elimination
of intercompany transactions.
|
B.
|
Cash
& Cash Equivalents
|
All
highly liquid investments with an original maturity of three months or less at
the date of purchase are considered cash equivalents.
|
C.
|
Revenues
|
Revenues
are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.
|
D.
|
Excise
and Utility Receipts Taxes
|
Excise
taxes and a portion of utility receipts taxes are included in rates charged to
customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $44.9 million in 2008, $41.8
million in 2007, and $39.7 million in 2006. Expense associated with
excise and utility receipts taxes are recorded as a component of Taxes other than income
taxes.
|
E.
|
Use
of Estimates
|
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these
estimates.
|
F.
|
Inventories
|
Inventories consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Gas
in storage – at LIFO cost
|
$ | 22.2 | $ | 16.7 | ||||
|
Gas
in storage – at average cost
|
0.4 | 63.7 | ||||||
|
Total
Gas in storage
|
22.6 | 80.4 | ||||||
|
Materials
& supplies
|
31.9 | 31.3 | ||||||
|
Fuel
(coal & oil) for electric generation
|
28.4 | 23.2 | ||||||
|
Other
|
1.7 | - | ||||||
|
Total
inventories
|
$ | 84.6 | $ | 134.9 | ||||
Based on
the average cost of gas purchased during December, the cost of replacing gas in
storage carried at LIFO cost exceeded LIFO cost at December 31, 2008, and 2007,
by approximately $35 million and $73 million, respectively. Gas in
storage of the Indiana regulated operations is stated at LIFO. All
other inventories are carried at average cost.
|
G.
|
Utility
Plant & Depreciation
|
Utility plant is stated at
historical cost, including AFUDC. Depreciation rates are established
through regulatory proceedings and are applied to all in-service utility
plant. The original cost of utility plant, together with depreciation
rates expressed as a percentage of original cost, follows:
|
At
and For the Year Ended December 31,
|
||||||||||||||||
|
(In
millions)
|
2008
|
2007
|
||||||||||||||
|
Original
Cost
|
Depreciation
Rates as a Percent of Original Cost
|
Original
Cost
|
Depreciation
Rates as a Percent of Original Cost
|
|||||||||||||
|
Gas
utility plant
|
$ | 2,157.6 | 3.5 | % | $ | 2,077.5 | 3.6 | % | ||||||||
|
Electric
utility plant
|
1,884.3 | 3.3 | % | 1,815.8 | 3.3 | % | ||||||||||
|
Common
utility plant
|
47.9 | 2.9 | % | 45.5 | 2.8 | % | ||||||||||
|
Construction
work in progress
|
245.5 | - | 124.1 | - | ||||||||||||
|
Total
original cost
|
$ | 4,335.3 | $ | 4,062.9 | ||||||||||||
SIGECO
and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW
Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's
share of the cost of this unit at December 31, 2008 is $63.5 million with
accumulated depreciation totaling $48.9 million. The construction
work-in-progress balance associated with SIGECO’s ownership interest totaled
$111.5 million at December 31, 2008. AGC and SIGECO also share
equally in the cost of operation and output of the unit. SIGECO's
share of operating costs is included in Other operating expenses in the Consolidated
Statements of Income.
Maintenance
and repairs, including the cost of removal of minor items of property and
planned major maintenance projects, are charged to expense as
incurred. When property that represents a retirement unit is replaced
or removed, the remaining historical value of such property is charged to Utility plant, with an
offsetting charge to Accumulated
depreciation. Costs to dismantle and remove retired property
are recovered through the depreciation rates identified above.
AFUDC
represents the cost of borrowed and equity funds which are used for construction
purposes, and charged to construction work in progress during the construction
period. AFUDC is included in Other – net in the
Consolidated Statements of Income. The total AFUDC capitalized into
utility plant and the portion of which was computed on borrowed and equity funds
for all periods reported follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
AFUDC
– borrowed funds
|
$ | 2.2 | $ | 3.5 | $ | 2.6 | ||||||
|
AFUDC
– equity funds
|
0.3 | 0.5 | 1.5 | |||||||||
|
Total
AFUDC
|
$ | 2.5 | $ | 4.0 | $ | 4.1 | ||||||
|
H.
|
Nonutility
Property
|
Nonutility property, net of
accumulated depreciation and amortization follows:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Computer
hardware & software
|
$ | 127.5 | $ | 114.5 | ||||
|
Land
& buildings
|
40.5 | 48.5 | ||||||
|
All
other
|
14.4 | 13.2 | ||||||
|
Nonutility
property - net
|
$ | 182.4 | $ | 176.2 | ||||
The depreciation of nonutility property is recorded over its estimated useful life, using the straight-line method of depreciation. Repairs and maintenance, which are not considered improvements and do not extend the useful life of the nonutility property, are charged to expense as incurred. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income. Nonutility property is presented net of accumulated depreciation and amortization totaling $133.5 million and $135.2 million as of December 31, 2008, and 2007, respectively. For the years ended December 31, 2008, 2007, and 2006, the Company capitalized interest totaling $2.0 million, $1.3 million, and $0.7 million, respectively, on nonutility plant construction projects.
|
I.
|
Goodwill
|
Goodwill
arising from business combinations is accounted for in accordance with SFAS No.
142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142
requires a portion of goodwill be charged to expense only when it is
impaired. The Company tests its goodwill for impairment at a
reporting unit level at least annually and that test is performed at the
beginning of each year. Impairment reviews consist of a comparison of
the fair value of a reporting unit to its carrying amount. If the
fair value of a reporting unit is less than its carrying amount, an impairment
loss is recognized in operations. Through December 31, 2008, no
goodwill impairments have been recorded. All of the Company’s
goodwill is included in the Gas Utility Services operating segment.
|
J.
|
Intangible
Assets
|
The
Company has emission allowances relating to its wholesale power marketing
operations totaling $1.6 million and $2.6 million at December 31, 2008 and 2007,
respectively. The value of the emission allowances are recognized as
they are consumed or sold on the open market.
|
K.
|
Regulation
|
Retail
public utility operations affecting Indiana customers are subject to regulation
by the IURC, and retail public utility operations affecting Ohio customers are
subject to regulation by the PUCO. The Company’s accounting policies
give recognition to the rate-making and accounting practices of these agencies
and to accounting principles generally accepted in the United States, including
the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation” (SFAS 71).
Refundable
or Recoverable Gas Costs and Cost of Fuel & Purchased Power
All
metered gas rates contain a gas cost adjustment clause that allows the Company
to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel. The net
energy cost of purchased power, subject to a variable benchmark based on NYMEX
natural gas prices, is also recovered through regulatory
proceedings. The Company records any under-or-over-recovery resulting
from gas and fuel adjustment clauses each month in revenues. A
corresponding asset or liability is recorded until the under or over-recovery is
billed or refunded to utility customers. The cost of gas sold is
charged to operating expense as delivered to customers, and the cost of fuel for
electric generation is charged to operating expense when consumed.
Regulatory
Assets and Liabilities
Regulatory
assets represent probable future revenues associated with certain incurred
costs, which will be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable expenditures by
the Company for removal costs or future reductions in revenues associated with
amounts that are to be credited to customers through the ratemaking
process. The Company assesses the recoverability of costs recognized
as regulatory assets and liabilities and the ability to continue to account for
its activities based on the criteria set forth in SFAS 71. Based on
current regulation, the Company believes such accounting is
appropriate. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be
required to determine any impairment to the carrying value of its utility plant
and other regulated assets.
Regulatory Assets consist of
the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Future
amounts recoverable from ratepayers related to:
|
||||||||
|
Income
taxes- deferred income taxes
|
$ | 12.1 | $ | 14.9 | ||||
|
Income
taxes- transition to SFAS 109
|
(0.7 | ) | (0.9 | ) | ||||
|
Interest
rate derivatives
|
- | 8.9 | ||||||
|
Asset
retirement obligations & other
|
8.5 | 10.9 | ||||||
| 19.9 | 33.8 | |||||||
|
Amounts
deferred for future recovery related to:
|
||||||||
|
Cost
recovery riders & other
|
1.7 | 1.9 | ||||||
| 1.7 | 1.9 | |||||||
|
Amounts
currently recovered in customer rates related to:
|
||||||||
|
Demand
side management programs
|
21.5 | 27.6 | ||||||
|
Unamortized
debt issue costs & hedging proceeds
|
38.4 | 25.0 | ||||||
|
Indiana
authorized trackers
|
13.8 | 42.3 | ||||||
|
Ohio
authorized trackers
|
11.6 | 10.4 | ||||||
|
Premiums
paid to reacquire debt & other
|
8.8 | 10.7 | ||||||
| 94.1 | 116.0 | |||||||
|
Total
regulatory assets
|
$ | 115.7 | $ | 151.7 | ||||
Of the $94.1 million currently being recovered in customer rates charged to customers, $21.5 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 13 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.
Regulatory
Liabilities
At
December 31, 2008 and 2007, the Company has approximately $315.1 million and
$307.2 million, respectively, in regulatory liabilities. Of these
amounts, $292.4 million and $288.3 million relate to cost of removal
obligations.
The
Company collects an estimated cost of removal of its utility plant through
depreciation rates established in regulatory proceedings. The Company
records amounts expensed in advance of payments as a Regulatory liability because
the liability does not meet the threshold of an asset retirement obligation as
defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its
related interpretations (SFAS 143).
|
L.
|
Asset
Retirement Obligations
|
A portion
of removal costs related to interim retirements of gas utility pipeline and
utility poles, certain asbestos-related issues, and reclamation activities meet
the definition of an asset retirement obligation (ARO). SFAS 143
requires entities to record the fair value of a liability for a legal ARO in the
period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the
related long-lived asset. The liability is accreted, and the
capitalized cost is depreciated over the useful life of the related
asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss. To the
extent regulation is involved, such gain or loss may be deferred.
ARO’s
included in Other
liabilities total $24.7 million and $16.4 million at December 31, 2008
and 2007, respectively. ARO’s included in Accrued liabilities total
$7.2 million and $9.5 million at December 31, 2008 and 2007,
respectively. During 2008, the Company recorded accretion of $0.9
million and increases in estimates, net of cash payments of $5.1
million. During 2007, the Company recorded accretion of $1.0 million
and increases in estimates, net of cash payments of $6.6 million.
|
M.
|
Impairment
Review of Long-Lived Assets
|
Long-lived
assets are reviewed as facts and circumstances indicate that the carrying amount
may be impaired. This review is performed in accordance with SFAS No.
144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS
144). SFAS 144 establishes one accounting model for all impaired
long-lived assets and long-lived assets to be disposed of by sale or
otherwise. SFAS 144 requires that the evaluation for impairment
involve the comparison of an asset’s carrying value to the estimated future cash
flows that the asset is expected to generate over its remaining
life. If this evaluation were to conclude that the carrying value of
the asset is impaired, an impairment charge would be recorded based on the
difference between the asset’s carrying amount and its fair value (less costs to
sell for assets to be disposed of by sale) as a charge to operations or
discontinued operations.
|
N.
|
Comprehensive
Income
|
Comprehensive
income is a measure of all changes in equity that result from the
non-shareholder transactions. This information is reported in the
Consolidated Statements of Common Shareholder’s Equity. A summary of
the components of and changes in Accumulated other comprehensive
income for the past three years follows:
|
2006
|
2007
|
2008
|
||||||||||||||||||||||||||
|
Beginning
|
Changes
|
End
|
Changes
|
End
|
Changes
|
End
|
||||||||||||||||||||||
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
||||||||||||||||||||||
|
(In
millions)
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
|||||||||||||||||||||
|
Cash
flow hedges
|
6.7 | (5.3 | ) | 1.4 | (0.9 | ) | 0.5 | (0.4 | ) | 0.1 | ||||||||||||||||||
|
Deferred
income taxes
|
(2.7 | ) | 2.2 | (0.5 | ) | 0.3 | (0.2 | ) | 0.2 | - | ||||||||||||||||||
|
Accumulated
other comprehensive income(loss)
|
$ | 4.0 | $ | (3.1 | ) | $ | 0.9 | $ | (0.6 | ) | $ | 0.3 | $ | (0.2 | ) | $ | 0.1 | |||||||||||
|
O.
|
Earnings
Per Share
|
Earnings
per share are not presented as Utility Holdings’ common stock is wholly owned by
Vectren.
|
P.
|
Other
Significant Policies
|
Included
elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 3) and derivatives (Note
10)
|
3.
|
Transactions
with Other Vectren Companies
|
Vectren Fuels,
Inc.
Vectren
Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines
from which SIGECO purchases coal used for electric generation. The
price of coal that is charged by Vectren Fuels to SIGECO is priced consistent
with contracts reviewed by the OUCC and on file with IURC. Amounts
paid for such purchases for the years ended December 31, 2008, 2007 and 2006,
totaled $119.8 million, $115.9 million, and $116.8 million,
respectively. Amounts owed to Vectren Fuels at December 31, 2008 and
2007 are included in Payables
to other Vectren companies.
Miller Pipeline
Corporation
Effective
July 1, 2006, Vectren purchased the remaining 50 percent ownership in Miller
Pipeline Corporation (Miller), making Miller a wholly owned subsidiary of
Vectren. Prior to the transaction, Miller was 50 percent owned by
Vectren and was accounted for by Vectren using the equity method of
accounting. Miller performs natural gas and water distribution,
transmission, and construction repair and rehabilitation primarily in the
Midwest and the repair and rehabilitation of gas, water, and wastewater
facilities nationwide. Miller’s customers include Utility Holdings’
utilities. Fees paid by Utility Holdings and its subsidiaries totaled
$39.9 million in 2008, $46.9 million in 2007, and $20.6 million in
2006. Amounts owed to Miller at December 31, 2008 and 2007 are
included in Payables to other
Vectren companies.
Vectren
Source
Vectren
Source, a nonutility wholly owned subsidiary of Vectren, provides natural gas
and other related products and services in the Midwest and Northeast United
States to over 170,000 residential and commercial customers. This
customer base reflects approximately 50,000 of VEDO’s customers that have
voluntarily opted to choose their natural gas supplier and the supply of natural
gas to nearly 40,000 equivalent customers in VEDO’s service territory as part of
VEDO’s process of exiting the merchant function, which began October 1,
2008. As part of VEDO’s exiting process on October 1, 2008, it
transferred its natural gas inventory at book value its new suppliers, and now
purchases natural gas from those suppliers, which include Vectren Source,
essentially on demand.
The cost
of natural gas inventory purchased by Vectren Source on October 1, 2008 totaled
approximately $31.6 million. From October 1, 2008 to December 31,
2008, the Company purchased natural gas from Vectren Source totaling
approximately $14.5 million, which represented approximately 2 percent of the
Company’s total gas purchased during 2008. Amounts charged by Vectren
Source for gas supply services is comprised of the monthly NYMEX settlement
price plus a fixed adder, as authorized by the PUCO. Amounts owed to
Vectren Source at December 31, 2008 are included in Payables to other Vectren
companies.
Support Services and
Purchases
Vectren
provides corporate and general and administrative services to the Company and
allocates costs to the Company, including costs for share-based compensation and
for pension and other postretirement benefits that are not directly charged to
subsidiaries. These costs have been allocated using various
allocators, including number of employees, number of customers and/or the level
of payroll, revenue contribution and capital
expenditures. Allocations are at cost. Utility Holdings
received corporate allocations totaling $45.8 million, $47.1 million, and $43.7
million for the years ended December 31, 2008, 2007 and 2006,
respectively.
Retirement Plans and Other
Postretirement Benefits
Vectren
has multiple defined benefit pension plans and postretirement plans that require
accounting as described in SFAS No. 158 “Employers’ Accounting
for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB
Statements No. 87, 88, 106, and 132(R)” (SFAS 158), which it adopted on December
31, 2006. An allocation of cost is determined, comprised of only
service cost and interest on that service cost, by subsidiary based on headcount
at each measurement date. These costs are directly charged to
individual subsidiaries. Other components of costs (such as interest
cost and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Neither plan assets nor
the ending liability is allocated to individual subsidiaries since these assets
and obligations are derived from corporate level decisions. Further,
Vectren satisfies the future funding requirements of plans and the payment of
benefits from general corporate assets. This allocation methodology
is consistent with “multiemployer” benefit accounting as described in SFAS 87
and 106.
For the
years ended December 31, 2008, 2007 and 2006, periodic pension costs totaling
$3.2 million, $5.2 million and $5.3 million, respectively, were directly charged
by Vectren to the Company. For the years ended December 31, 2008,
2007 and 2006, other periodic postretirement benefit costs totaling $0.3
million, $0.5 million and $0.6 million, respectively, were directly charged by
Vectren to the Company. As of December 31, 2008 and 2007, $38.5
million and $37.4 million, respectively, is included in Deferred credits & other
liabilities and represents costs directly charged to the Company that is
yet to be funded to Vectren.
Cash Management
Arrangements
The
Company participates in Vectren’s centralized cash management
program.
Share-Based Incentive Plans
and Deferred Compensation Plans
Utility
Holdings does not have share-based compensation plans separate from
Vectren. An insignificant number of Utility Holdings’ employees
participate in Vectren’s share-based compensation plans. The Company
recognizes its allocated portion of expenses in accordance with FASB Statement
123 (revised 2004), “Share-Based Payments” (SFAS 123R). As of
December 31, 2008 and 2007, $26.6 million and $29.1 million, respectively, is
included in Deferred credits
& other liabilities and represents costs directly charged to the
Company that is yet to be funded to Vectren.
Income
Taxes
Vectren
files a consolidated federal income tax return. Pursuant to a
subsidiary tax sharing agreement and for financial reporting purposes, Utility
Holdings’ current and deferred tax expense is computed on a separate company
basis. Current taxes payable/receivable are settled with Vectren in
cash. The liability method of accounting is used for income taxes
under which deferred income taxes are recognized to reflect the tax effect of
temporary differences between the book and tax bases of assets and liabilities
at currently enacted income tax rates. Significant components of the
net deferred tax liability follow:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Noncurrent
deferred tax liabilities (assets):
|
||||||||
|
Depreciation
& cost recovery timing differences
|
$ | 330.9 | $ | 278.8 | ||||
|
Regulatory
assets recoverable through future rates
|
27.8 | 25.3 | ||||||
|
Demand
side management programs
|
- | 7.9 | ||||||
|
Other
comprehensive income
|
0.1 | 0.3 | ||||||
|
Employee
benefit obligations
|
(22.1 | ) | (19.7 | ) | ||||
|
Regulatory
liabilities to be settled through future rates
|
(15.7 | ) | (10.4 | ) | ||||
|
Other
– net
|
11.1 | 4.7 | ||||||
|
Net
noncurrent deferred tax liability
|
332.1 | 286.9 | ||||||
|
Current
deferred tax liabilities (assets):
|
||||||||
|
Deferred
fuel costs - net
|
2.6 | (1.4 | ) | |||||
|
Alternative
minimum tax carryforward
|
(11.2 | ) | - | |||||
|
Demand
side management programs
|
8.8 | - | ||||||
|
Other
– net
|
(3.3 | ) | 6.3 | |||||
|
Net
deferred tax liability
|
$ | 329.0 | $ | 291.8 | ||||
At December 31, 2008 and 2007, investment tax credits totaling $6.9 million and $8.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. At December 31, 2008, the Company has alternative minimum tax carryforwards of $11.2 million, which do not expire.
A
reconciliation of the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Statutory
rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State
and local taxes-net of federal benefit
|
3.4 | 3.9 | 5.5 | |||||||||
|
Tax
law change
|
- | 0.2 | (2.2 | ) | ||||||||
|
Amortization
of investment tax credit
|
(0.7 | ) | (1.0 | ) | (1.4 | ) | ||||||
|
Adjustment
to income tax accruals
|
- | - | (2.8 | ) | ||||||||
|
All
other - net
|
0.1 | 0.4 | 0.2 | |||||||||
|
Effective
tax rate
|
37.8 | % | 38.5 | % | 34.3 | % | ||||||
The
components of income tax expense and utilization of investment tax credits
follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 3.7 | $ | 43.7 | $ | 43.3 | ||||||
|
State
|
9.2 | 8.6 | 10.8 | |||||||||
|
Total
current taxes
|
12.9 | 52.3 | 54.1 | |||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
52.7 | 11.9 | (0.9 | ) | ||||||||
|
State
|
3.3 | 4.2 | (3.5 | ) | ||||||||
|
Total
deferred taxes
|
56.0 | 16.1 | (4.4 | ) | ||||||||
|
Amortization
of investment tax credits
|
(1.3 | ) | (1.7 | ) | (2.0 | ) | ||||||
|
Total
income tax expense
|
$ | 67.6 | $ | 66.7 | $ | 47.7 | ||||||
Accounting for Uncertainty in Income Taxes
On
January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48)
“Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109,
“Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold
and measurement attribute for financial statement recognition and measurement of
tax positions taken or expected to be taken in an income tax return. FIN
48 also provides guidance related to reversal of tax positions, balance sheet
classification, interest and penalties, interim period accounting, disclosure
and transition.
As a
result of the implementation of FIN 48, the Company recognized an approximate
$0.9 million increase in the liability for unrecognized tax benefits, which was
accounted for as a reduction to the January 1, 2007 balance of Retained
earnings. At adoption, the total amount of gross unrecognized
tax benefits was $7.0 million.
Following
is a roll forward of the total amount of unrecognized tax benefits for the years
ended December 31, 2008 and 2007:
|
(in
millions)
|
2008
|
2007
|
||||||
|
Unrecognized
tax benefits at January 1
|
$ | 3.8 | $ | 7.0 | ||||
|
Gross Increases -
tax positions in prior periods
|
0.3 | 0.3 | ||||||
|
Gross Decreases -
tax positions in prior periods
|
(3.6 | ) | (3.5 | ) | ||||
|
Unrecognized tax
benefits at December 31
|
$ | 0.5 | $ | 3.8 | ||||
The change in unrecognized tax benefits during 2008 totaled $3.3 million, almost none of which impacted the effective rate. During 2007 the change in unrecognized tax benefits totaled $3.2 million, of which $0.3 million impacted the effective tax rate. The amount of unrecognized tax benefits, which, if recognized, that would impact the effective tax rate as of December 31, 2008 and 2007 was insignificant.
As of
December 31, 2008, the remaining unrecognized tax benefit relates to tax
positions for which the ultimate deductibility is highly certain but for which
there is uncertainty about the timing of such deductibility. Because of
the impact of deferred tax accounting, other than interest and penalties, the
disallowance of the shorter deductibility period would not affect the annual
effective tax rate but would accelerate the payment of cash to the taxing
authority.
The
Company accrues interest and penalties associated with unrecognized tax benefits
in Income taxes.
The Company recognized expense related to interest and penalties totaling less
than $0.1 million in 2008 and approximately $0.5 million in
2007. Prior to the adoption of FIN 48, activity related to interest
and penalties was recorded at the Vectren level. As of December 31,
2008 and 2007, the Company had approximately $0.2 million and $0.5 million,
respectively, accrued for the payment of interest and penalties.
The net
liability on the Consolidated Balance Sheet for unrecognized tax benefits
inclusive of interest, penalties and secondary impacts which are a component of
the Deferred taxes,
totaled $0.7 million and $4.3 million, respectively, at December 31, 2008 and
2007.
From time
to time, Vectren may consider changes to filed positions that could impact the
Company's 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.
Utility
Holdings does not file federal or state income tax returns separate from those
filed by its parent, Vectren Corporation. Vectren files a
consolidated U.S. federal income tax return, and Vectren and/or certain of its
subsidiaries file returns in various states. The Internal Revenue Service
(IRS) has conducted examinations of Vectren’s U.S. federal income tax returns
for tax years through December 31, 2005. The State of Indiana, Vectren’s
primary state tax jurisdiction, has conducted examinations of state income tax
returns for tax years through December 31, 2002. The statutes of
limitations for assessment of federal and Indiana income tax have expired with
respect to tax years through 2002.
|
4.
|
Transactions
with Affiliated Vectren Companies
|
ProLiance Holdings, LLC
(ProLiance)
ProLiance
Holdings, LLC (ProLiance), a nonutility energy marketing
affiliate of Vectren and Citizens Energy Group (Citizens), provides services to
a broad range of municipalities, utilities, industrial operations, schools, and
healthcare institutions located throughout the Midwest and Southeast United
States. ProLiance’s customers include Vectren’s Indiana utilities and
nonutility gas supply operations as well as Citizens’
utilities. ProLiance’s primary businesses include gas marketing, gas
portfolio optimization, and other portfolio and energy management services.
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.
Transactions
with ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2008, 2007 and 2006 totaled $739.3 million, $602.2
million, and $610.2 million, respectively. Amounts owed to ProLiance
at December 31, 2008 and 2007, for those purchases were $72.8 million and $66.9
million, respectively, and are included in Accounts payable to affiliated
companies in the Consolidated Balance Sheets. The Company
purchased approximately 71 percent of its gas through ProLiance in 2008 and 2007
and 72 percent in 2006. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.
Other Affiliate
Transactions
Vectren
has an ownership interest in Reliant Services LLC (Reliant) that is accounted
for using the equity method of accounting. Reliant performed
facilities locating and meter reading services for the Company in
2006. For the year ended December 31, 2006, fees for these services
paid by the Company to Reliant were approximately $7.4
million. Amounts charged were market based.
|
5.
|
Borrowing
Arrangements
|
Long-Term
Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
|||||
|
(In
millions)
|
2008
|
2007
|
|||
|
Utility
Holdings
|
|||||
|
Fixed
Rate Senior Unsecured Notes
|
|||||
|
2011,
6.625%
|
$ 250.0
|
$ 250.0
|
|||
|
2013,
5.25%
|
100.0
|
100.0
|
|||
|
2015,
5.45%
|
75.0
|
75.0
|
|||
|
2018,
5.75%
|
100.0
|
100.0
|
|||
|
2035,
6.10%
|
75.0
|
75.0
|
|||
|
2036,
5.95%
|
99.1
|
100.0
|
|||
|
2039,
6.25%
|
124.3
|
-
|
|||
|
Total
Utility Holdings
|
823.4
|
700.0
|
|||
|
SIGECO
|
|||||
|
First
Mortgage Bonds
|
|||||
|
2016,
1986 Series, 8.875%
|
13.0
|
13.0
|
|||
|
2020,
1998 Pollution Control Series B, 4.50%, tax exempt
|
4.6
|
4.6
|
|||
|
2024,
2000 Environmental Improvement Series A, 4.65%, tax exempt
|
22.5
|
22.5
|
|||
|
2029,
1999 Senior Notes, 6.72%
|
80.0
|
80.0
|
|||
|
2030,
1998 Pollution Control Series B, 5.00%, tax exempt
|
22.0
|
22.0
|
|||
|
2015,
1985 Pollution Control Series A, current adjustable rate 0.9%, tax
exempt,
|
|||||
|
2008 weighted average:
2.78%
|
9.8
|
9.8
|
|||
|
2023,
1993 Environmental Improvement Series B, 5.15%, tax exempt
|
22.6
|
22.6
|
|||
|
2025,
1998 Pollution Control Series A, current adjustable rate 1.2%, tax
exempt,
|
|||||
|
2008 weighted
average: 2.94%
|
31.5
|
31.5
|
|||
|
2030,
1998 Pollution Control Series C, 5.35%, tax exempt
|
22.2
|
22.2
|
|||
|
2041,
2007 Pollution Control Series, 5.45%, tax exempt
|
17.0
|
17.0
|
|||
|
Total
SIGECO
|
245.2
|
245.2
|
|||
|
Indiana
Gas
|
|||||
|
Senior
Unsecured Notes
|
|||||
|
2013,
Series E, 6.69%
|
5.0
|
5.0
|
|||
|
2015,
Series E, 7.15%
|
5.0
|
5.0
|
|||
|
2015,
Series E, 6.69%
|
5.0
|
5.0
|
|||
|
2015,
Series E, 6.69%
|
10.0
|
10.0
|
|||
|
2025,
Series E, 6.53%
|
10.0
|
10.0
|
|||
|
2027,
Series E, 6.42%
|
5.0
|
5.0
|
|||
|
2027,
Series E, 6.68%
|
1.0
|
1.0
|
|||
|
2027,
Series F, 6.34%
|
20.0
|
20.0
|
|||
|
2028,
Series F, 6.36%
|
10.0
|
10.0
|
|||
|
2028,
Series F, 6.55%
|
20.0
|
20.0
|
|||
|
2029,
Series G, 7.08%
|
30.0
|
30.0
|
|||
|
Total
Indiana Gas
|
121.0
|
121.0
|
|||
|
Total
long-term debt outstanding
|
1,189.6
|
1,066.2
|
|||
|
Debt
subject to tender
|
(80.0)
|
-
|
|||
|
Unamortized
debt premium & discount - net
|
(3.2)
|
(3.6)
|
|||
|
Treasury
debt
|
(41.3)
|
-
|
|||
|
Total
long-term debt-net
|
$
1,065.1
|
$
1,062.6
|
|||
Utility
Holdings 2008 Debt Issuance
In March
2008, Utility Holdings issued at par $125 million in 6.25 percent senior
unsecured notes due April 1, 2039 (2039 Notes). The 2039 Notes are
guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas,
and VEDO. These guarantees are full and unconditional and joint and
several.
The 2039
Notes have no sinking fund requirements, and interest payments are due
monthly. The notes may be called by Utility Holdings, in whole or in
part, at any time on or after April 1, 2013, at 100 percent of principal amount
plus accrued interest. During 2007, Utility Holdings entered into
several interest rate hedges with an $80 million notional
amount. Upon issuance of the notes, these instruments were settled
resulting in the payment of approximately $9.6 million, which was recorded as a
Regulatory asset
pursuant to existing regulatory orders. The value paid is being
amortized as an increase to interest expense over the life of the
issue. The proceeds from the sale of the 2039 Notes less settlement
of the hedging arrangements and payments of issuance costs amounted to
approximately $111.1 million.
Utility
Holdings 2006 Debt Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95 percent senior
unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes
were priced at par. The 2036 Notes are guaranteed by Utility
Holdings’ three public utilities: SIGECO, Indiana Gas, and
VEDO. These guarantees are full and unconditional and joint and
several. These notes, as well as the timely payment of principal and
interest, are insured by a financial guaranty insurance policy by Financial
Guaranty Insurance Company (FGIC).
The 2036
Notes have no sinking fund requirements, and interest payments are due
quarterly. The notes may be called by Utility Holdings, in whole or
in part, at any time on or after October 1, 2011, at 100 percent of principal
amount plus accrued interest. During the first and second quarters of
2006, Utility Holdings entered into several interest rate hedges with a $100
million notional amount. Upon issuance of the notes, these
instruments were settled resulting in the payment of approximately $3.3 million,
which was recorded as a Regulatory asset pursuant to
existing regulatory orders. The value paid is being amortized as an
increase to interest expense over the life of the issue. The proceeds
from the sale of the 2036 Notes, settlement of the hedging arrangements, and
payments of issuance costs totaled approximately $92.8 million.
Long-Term
Debt Put and Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. Other than certain instruments that
can be put to the Company upon the death of the holder (death puts), these put
or call provisions are not triggered by specific events, but are based upon
dates stated in the note agreements. During 2008 the Company repaid
approximately $1.6 million related to death puts. In 2007 and 2006,
no debt was put to the Company. Debt which may be put to the Company
for reasons other than a death during the years following 2008 (in millions) is
$80.0 in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and
thereafter. Debt that may be put to the Company within one year is
classified as Long-term debt
subject to tender in current liabilities.
Auction
Rate Securities
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt had a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate was to reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation (Ambac).
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax-exempt auction rate mode long-term debt, including the $17
million issued in December 2007, of its plans to convert that debt from its
current auction rate mode into a daily interest rate mode. In March
2008, the debt was tendered at 100 percent of the principal amount plus accrued
interest. During March 2008, SIGECO remarketed approximately $61.8
million of these instruments at interest rates that are fixed to maturity,
receiving proceeds, net of issuance costs, of approximately $60.0
million. The terms are $22.6 million at 5.15 percent due in 2023,
$22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due
in 2041. The remaining $41.3 million continues to be held in treasury
and is expected to be remarketed in 2009.
Utility
Holdings and Indiana Gas Debt Calls
In 2006,
the Company called at par $100.0 million of Utility Holdings senior unsecured
notes originally due in 2031. The note had a stated interest rate of
7.25 percent.
Other
Financing Transactions
Other
Company debt totaling $6.5 million in 2007 was retired as
scheduled.
Future
Long-Term Debt Sinking Fund Requirements and Maturities
The
annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of
the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the
Trustee of unfunded property additions in the prescribed amount as provided in
the Mortgage Indenture. SIGECO intends to meet the 2009 sinking fund
requirement by this means and, accordingly, the sinking fund requirement for
2009 is excluded from Current
liabilities in the Consolidated Balance Sheets. At December
31, 2008, $1.0 billion of SIGECO's utility plant remained unfunded under
SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance
subject to the Mortgage Indenture approximated $2.3 billion at December 31,
2008.
Consolidated
maturities of long-term debt during the five years following 2008 (in millions)
are zero in 2009 and 2010, $250.0 in 2011, zero in 2012, and $105.0 in
2013.
Short-Term
Borrowings
At
December 31, 2008, the Company had $520 million of short-term borrowing
capacity, of which approximately $328 million was available. Interest
rates and outstanding balances associated with short-term borrowing arrangements
follows.
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Weighted
average commercial paper and bank loans
|
||||||||||||
|
outstanding
during the year
|
$ | 178.2 | $ | 253.6 | $ | 177.5 | ||||||
|
Weighted
average interest rates during the year
|
||||||||||||
|
Commercial
paper
|
3.76 | % | 5.54 | % | 5.16 | % | ||||||
|
Bank
loans
|
3.42 | % | N/A | N/A | ||||||||
|
At
December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
||||||||||
|
Commercial
paper
|
$ | 91.5 | $ | 385.9 | ||||||||
|
Bank
loans
|
100.4 | - | ||||||||||
|
Total
short-term borrowings
|
$ | 191.9 | $ | 385.9 | ||||||||
Impacts on Short-Term Borrowings from Recent Events in Credit Markets
Historically,
the Company has funded its short-term borrowing needs through the commercial
paper market. In 2008, the Company’s access to longer term commercial
paper was significantly reduced as a result of the continued turmoil and
volatility in the financial markets. As a result, the Company has met
working capital requirements through a combination of A2/P2 commercial paper
issuances and draws on its $515 million commercial paper back-up credit
facilities. In addition, the Company increased its cash
investments by approximately $40 million during the fourth quarter of
2008. This cash position was liquidated in January 2009 based upon
improvements in the short-term debt and commercial paper markets; and therefore,
resulted in an increase to the available short-term debt capacity.
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 Utility
Holdings’ short-term debt agreement expiring in 2010 contains a covenant that
the ratio of consolidated total debt to consolidated total capitalization will
not exceed 65 percent. As of December 31, 2008, the Company was in
compliance with all financial covenants.
|
6.
|
Common
Shareholder’s Equity
|
On June
27, 2008, Vectren physically settled an equity forward agreement associated with
a 2007 public offering of its common stock. Vectren transferred net
proceeds of approximately $124.8 million to Utility Holdings. The
proceeds received were recorded as an increase to Common Stock in Common
Shareholder’s Equity and are presented in the Statement of Cash Flows as a
financing activity.
In
addition to the $124.8 million capital contribution above, during the years
ended December 31, 2008, 2007 and 2006, the Company has cumulatively received
additional capital of $25.3 million from Vectren. Of that total,
$20.0 million was funded by Vectren’s nonregulated operations, and $5.3 million
was funded by new share issues from Vectren’s dividend reinvestment
plan.
|
7.
|
Commitments
& Contingencies
|
Commitments
Future
minimum lease payments required under operating leases that have initial or
remaining noncancelable lease terms in excess of one year during the five years
following 2008 and thereafter (in millions) are $1.0 in 2009, $0.6 in 2010, $0.3
in 2011, $0.2 in 2012, $0.2 in 2013, and zero thereafter. Total lease
expense (in millions) was $1.6 in 2008, $1.3 in 2007, and $2.4 in
2006. Firm purchase commitments for commodities and utility plant
total $6.8 million in 2009.
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase natural gas, coal, and electricity as well as certain transportation
and storage rights. Costs arising from these commitments, while
significant, are pass-through costs, generally collected dollar-for-dollar from
retail customers through regulator-approved cost recovery
mechanisms.
Legal
Proceedings
The
Company is party to various legal proceedings arising in the normal course of
business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position, results of operations or cash
flows.
|
8.
|
Environmental
Matters
|
Clean Air
Act
In March
of 2005, the USEPA finalized the Clean Air Interstate Rule (CAIR). CAIR is an
allowance cap and trade program requiring further reductions from coal-burning
power plants in NOx emissions beginning January 1, 2009 and SO2 emissions
beginning January 1, 2010, with a second phase of reductions in 2015. On
July 11, 2008, the US Court of Appeals for the District of Columbia vacated the
federal CAIR regulations. Various parties filed motions for
reconsideration, and on December 23, 2008, the Court reinstated the CAIR
regulations and remanded the regulations back to the USEPA for promulgation of
revisions in accordance with the Court’s July 11, 2008 Order. Thus,
the original version of CAIR promulgated in March of 2005 remains effective
while USEPA revises it per the Court’s guidance. It is possible that
a revised CAIR will require further reductions in NOx and SO2 from
SIGECO’s generating units. SIGECO is in compliance with the current
CAIR Phase I annual NOx reduction requirements in effect on January 1,
2009. Utilization of the Company’s inventory of NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of the these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. It is quite possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress. It is also possible that the USEPA will promulgate
a revised mercury regulation in 2009.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. Prior to being included in base rates, return
on investments made and recovery of related operating expenses were recovered
through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. Through
December 31, 2008, the Company has invested approximately $97.6 million in this
project. The scrubber was placed into service on January 1, 2009, and
the Company expects the total project investment to approximate $100 million
once all post in-service investments are completed. Recovery through
a rider mechanism of associated operating expenses including depreciation
expense associated with the scrubber also began on January 1,
2009. With the SO2 scrubber
fully operational, SIGECO is positioned for compliance with the additional
SO2
reductions required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s
coal fired generating fleet is 100 percent scrubbed for SO2 and 90
percent controlled for NOx. SIGECO's investments in scrubber, SCR and
fabric filter technology allows for compliance with existing regulations and
should position it to comply with future reasonable pollution control
legislation, if and when, reductions in mercury and further reductions in NOx
and SO2 are
promulgated by USEPA.
Climate
Change
There are
currently several forms of legislation being circulated at the federal level
addressing the climate change issue. These proposals generally
involve either: 1) a “cap and trade” approach where there is a progressive cap
on greenhouse gas emissions and an auctioning and subsequent trading of
allowances among those that emit greenhouse gases or 2) a carbon
tax. Currently no legislation has passed either house of
Congress.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in the State
of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas
Reduction Accord, and its legislature has in the recent past debated, but did
not pass, renewable energy portfolio standards. It is expected that
the Indiana State legislature will address a renewable energy portfolio standard
again in 2009.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from new motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. Should the USEPA find such endangerment, it is likely
that major stationary sources will be subject to regulation under the
Act. In 2008, the USEPA published its Advanced Notice of Proposed
Rulemaking in which the agency solicited comment as to whether it is appropriate
or effective to regulate greenhouse gas emissions under the Act. The
Obama administration has asserted that it will act on the endangerment finding
in the absence of comprehensive federal legislation within the next 18
months.
Impact
of Legislative Actions and Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants and
possibly natural gas distribution businesses. Further, any legislation
would likely impact the Company’s generation resource planning decisions.
At this time and in the absence of final legislation, compliance costs and other
effects associated with reductions in greenhouse gas emissions or obtaining
renewable energy sources remain uncertain. The Company has gathered
preliminary estimates of the costs to comply with a cap and trade approach to
controlling greenhouse gas emissions. A preliminary investigation
demonstrated costs to comply would be significant, first to operating expenses
for the purchase of allowances, and later to capital expenditures as technology
becomes available to control greenhouse gas emissions. However, these
compliance cost estimates are very sensitive to highly uncertain assumptions,
including allowance prices. Costs to purchase allowances that cap
greenhouse gas emissions should be considered a cost of providing electricity,
and as such, the Company believes recovery should be timely reflected in rates
charged to customers. Approximately 22 percent of electric volumes
sold in 2008 were delivered to municipal and other wholesale
customers. As such, the Company has some flexibility to modify the
level of these transactions to reduce overall emissions and reduce costs
associated with complying with new environmental regulations.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that owned or
operated these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded cumulative costs
that it reasonably expects to incur totaling approximately $21.6
million. The estimated accrued costs are limited to Indiana Gas’
share of the remediation efforts. Indiana Gas has arrangements in
place for 19 of the 26 sites with other potentially responsible parties (PRP),
which serve to limit Indiana Gas’ share of response costs at these 19 sites to
between 20 percent and 50 percent.
With
respect to insurance coverage, Indiana Gas has received and recorded settlements
from all known insurance carriers under insurance policies in effect when these
plants were in operation in an aggregate amount approximating $20.5
million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has filed a declaratory judgment action against its insurance carriers seeking a
judgment finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit. While the total costs that may be incurred in connection
with addressing these sites cannot be determined at this time, SIGECO has
recorded cumulative costs that it reasonably expects to incur totaling
approximately $8.7 million. With respect to insurance coverage,
SIGECO has received and recorded settlements from insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.0 million.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. While
the Company’s utilities have recorded all costs which they presently expect to
incur in connection with activities at these sites, it is possible that future
events may require some level of additional remedial activities which are not
presently foreseen and those costs may not be subject to PRP or insurance
recovery. As of December 31, 2008, approximately $6.5 million is
included in Other
Liabilities related to the remediation of these sites.
Jacobsville Superfund
Site
On July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The
USEPA has identified four sources of historic lead
contamination. These four sources shut down manufacturing operations
years ago. When drawing up the boundaries for the listing, the USEPA
included a 250 acre block of properties surrounding the Jacobsville
neighborhood, including the Company’s Wagner Operations Center. The
Company's property has not been named as a source of the lead contamination, nor
does the USEPA's soil testing to date indicate that the property contains lead
contaminated soils. The Company's own soil testing, completed during
the construction of the Operations Center, did not indicate that the property
contains lead contaminated soils. At this time, the Company
anticipates only additional soil testing could be requested by the USEPA at some
future date.
|
9.
|
Rate
& Regulatory Matters
|
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Order Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also adjusts the rate design that will be used to collect the agreed-upon
revenue from VEDO's residential customers. The order authorizes the
use of a straight fixed variable rate design which places all, or most, of the
fixed cost recovery in the customer service charge. Using a phased in
approach, revenues based on volumes sold will be entirely replaced with a fixed
charge after one year. A straight fixed variable design
mitigates some weather risk as well as the effects of declining usage, similar
to the Company’s lost margin recovery mechanism, which expired when this new
rate design went into effect in February 2009. In 2008, results include
approximately $4.3 million of revenue from the existing lost margin recovery
mechanism that will not continue once this base rate increase is in
effect. The OCC has filed a request for rehearing on the rate design
finding by the PUCO. The rehearing request mirrors similar requests
filed by the OCC in each case where the PUCO has approved similar rate designs,
and all such requests have been denied.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of bad debt and percent of
income payment plan (PIPP) expenses; base rate recovery of pipeline integrity
management expense; timely recovery of costs associated with the accelerated
replacement of bare steel and cast iron pipes, as well as certain service
risers; and expanded conservation programs now totaling up to $5 million in
annual expenditures.
Vectren Energy Delivery of
Ohio, Inc. Begins Process to Exit the Merchant Function
On August
20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers
to provide the gas commodity to the Company for resale to its customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. This auction, which is effective from October 1, 2008 through
March 31, 2010, is the initial step in exiting the merchant function in the
Company’s Ohio service territory. The approach eliminates the
need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits. On October 1st, VEDO’s
entire natural gas inventory was transferred, receiving proceeds of
approximately $107 million. The PUCO has also provided for an Exit
Transition Cost rider, which allows the Company to recover costs associated with
the transition. As the cost of gas is currently passed through to
customers through a PUCO approved recovery mechanism, the impact of exiting the
merchant function should not have a material impact on Company earnings or
financial condition.
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
the settlement agreement reached in its Vectren North gas rate case. The
order provided for a base rate increase of $16.3 million and a return on equity
(ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate
base of approximately $793 million. The order also provides for the
recovery of $10.6 million of costs through separate cost recovery mechanisms
rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $20 million
and the treatment cannot extend beyond four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s electric rate case. The order
provided for an approximate $60.8 million electric rate increase to cover the
Company’s cost of system growth, maintenance, safety and reliability. The
order provided for, among other things: recovery of ongoing costs and deferred
costs associated with the MISO; operations and maintenance (O&M) expense
increases related to managing the aging workforce, including the development of
expanded apprenticeship programs and the creation of defined training programs
to ensure proper knowledge transfer, safety and system stability; increased
O&M expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by sharing equally with customers any
profit earned above or below $10.5 million of wholesale power margin; recovery
of and return on the investment in past demand side management programs to help
encourage conservation during peak load periods; timely recovery of the
Company’s investment in certain new electric transmission projects that benefit
the MISO infrastructure; an overall rate of return of 7.32 percent on rate base
of approximately $1,044 million and an allowed ROE of 10.4 percent.
Vectren South Gas Base Rate
Order Received
On August
1, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s gas rate case. The order provided
for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an
overall rate of return of 7.2 percent on rate base of approximately $122
million. The order also provided for the recovery of $2.6 million of
costs through separate cost recovery mechanisms rather than base
rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $3 million
and the treatment cannot extend beyond three years on each project.
With this
order, the Company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a bad debt expense level based on historical experience
and unaccounted for gas through the existing gas cost adjustment mechanism, and
tracking of pipeline integrity management expense.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission
needs of much of the Midwest and maintains operational control over the
Company’s electric transmission facilities as well as that of other Midwest
utilities. Since April 1, 2005, the Company has been an active participant
in the MISO energy markets, bidding its owned generation into the Day Ahead and
Real Time markets and procuring power for its retail customers at Locational
Marginal Pricing (LMP) as determined by the MISO market.
The
Company is typically in a net sales position with MISO as generation capacity is
in excess of that needed to serve native load and is only occasionally in a net
purchase position. When the Company is a net seller such net revenues are
included in Electric Utility
revenues and when the Company is a net purchaser such net purchases are
included in Cost of fuel and
purchased power. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO day ahead and real-time markets. Net revenues from wholesale
activities included in Electric Utility revenues
totaled $57.6 million in 2008, $39.8 million in 2007 and $29.8 million in
2006.
The
Company also receives transmission revenue that results from other members’ use
of the Company’s transmission system. These revenues are also
included in Electric Utility
revenues. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered/refunded through tracking
mechanisms.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM
The need
to expend capital for improvements to the regional transmission system, both to
SIGECO’s facilities as well as to those facilities of adjacent utilities, over
the next several years is expected to be significant. The Company
timely recovers its investment in certain new electric transmission projects
that benefit the MISO infrastructure at a FERC approved rate of
return.
|
10.
|
Derivatives
& Other Financial Instruments
|
Accounting Policy for
Derivatives
The
Company periodically executes derivative contracts in the normal course of
operations while buying and selling commodities to be used in operations,
optimizing its generation assets, and managing risk. The Company
accounts for its derivative contracts in accordance with SFAS 133, “Accounting
for Derivatives” and its related amendments and interpretations. In
most cases, SFAS 133 requires a derivative to be recorded on the balance sheet
as an asset or liability measured at its market value and that a change in the
derivative's market value be recognized currently in earnings unless specific
hedge criteria are met.
When an
energy contract that is a derivative is designated and documented as a normal
purchase or normal sale, it is exempted from mark-to-market
accounting. Otherwise, energy contracts and financial contracts that
are derivatives are recorded at market value as current or noncurrent assets or
liabilities depending on their value and on when the contracts are expected to
be settled. Contracts and any associated collateral with
counter-parties subject to master netting arrangements are presented net in the
Consolidated Balance Sheets. The offset resulting from carrying the
derivative at fair value on the balance sheet is charged to earnings unless it
qualifies as a hedge or is subject to SFAS 71. When hedge accounting
is appropriate, the Company assesses and documents hedging relationships between
the derivative contract and underlying risks as well as its risk management
objectives and anticipated effectiveness. When the hedging
relationship is highly effective, derivatives are designated as
hedges. The market value of the effective portion of the hedge is
marked to market in accumulated other comprehensive income for cash flow
hedges. Ineffective portions of hedging arrangements are
marked-to-market through earnings. For fair value hedges, both the
derivative and the underlying hedged item are marked to market through
earnings. The offset to contracts affected by SFAS 71 are
marked-to-market as a regulatory asset or liability. Market value for
derivative contracts is determined using quoted market prices from independent
sources. Following is a more detailed discussion of the Company’s use
of mark-to-market accounting in three primary areas: SO2 emission
allowance risk management, natural gas procurement, and interest rate risk
management.
SO2 Emission Allowance Risk
Management
The
Company’s wholesale power marketing operations are exposed to price risk
associated with SO2 emission
allowances. To mitigate this risk, the Company executed call options
to hedge wholesale emission allowance utilization in future
periods. The Company designated and documented these derivatives as
cash flow hedges. At December 31, 2008, a deferred gain of
approximately $0.2 million remains in accumulated comprehensive income related
to these call options which will be recognized in earnings as emission
allowances are utilized. Hedge ineffectiveness totaled $0.2 million
of expense in 2006. No SO2 emission
allowance hedges are outstanding as of December 31, 2008.
Natural Gas Procurement
Activity
The
Company’s regulated operations have limited exposure to commodity price risk for
purchases and sales of natural gas and electricity for retail customers due to
current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms. Although regulated operations are exposed
to limited commodity price risk, volatile natural gas prices can result in
higher working capital requirements, increased expenses including interest
costs, uncollectible accounts expense, and unaccounted for gas, and some level
of price-sensitive reduction in volumes sold. The Company may
mitigate these risks by using derivative contracts. These contracts
are subject to regulation which allows for reasonable and prudent hedging costs
to be recovered through rates. When regulation is involved, SFAS 71
controls when the offset to mark-to-market accounting is recognized in
earnings. At December 31, 2008 and 2007, the market values of these
contracts were not significant.
Interest Rate
Management
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on interest
expense. The Company has used interest rate swaps and treasury locks
to hedge forecasted debt issuances and other interest rate swaps to manage
interest rate exposure.
As of
December 31, 2008, no interest rate swaps were outstanding. At
December 31, 2007, the fair value liability associated with interest rate swaps
was $8.9 million. Related to derivative instruments associated with
completed debts issuances, an approximate $7.7 million net regulatory asset
remains at December 31, 2008. In 2008, $0.3 million was reclassified as a
decrease to interest expense, $0.6 million reduced interest expense in 2007, and
$0.7 million reduced interest expense in 2006. The Company estimates
a $0.3 million reduction to interest expense will occur in 2009 related to the
amortization of this net position.
Fair Value
Measurements
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
157). SFAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles (GAAP), and
expands disclosures about fair value measurements. SFAS 157 does not
require any new fair value measurements; however, the standard will impact how
other fair value based GAAP is applied. Subsequently, the FASB issued
FSP FAS 157-2 which delayed the effective date of SFAS 157 for all nonfinancial
assets and nonfinancial liabilities, except those that are recognized or
disclosed at fair value in the financial statements on a recurring basis (at
least annually) to fiscal years beginning after November 15,
2008. The Company adopted SFAS 157 on January 1, 2008, except as it
applies to those nonfinancial assets and nonfinancial liabilities as described
in FSP FAS 157-2. The partial adoption of SFAS 157 did not materially
impact the Company’s financial position, results of operations or cash
flows. The potential impact of applying SFAS 157 to its nonfinancial
assets and liabilities is not expected to have a material impact on the
Company’s consolidated financial statements.
63
The
Company measures certain financial instruments, primarily derivatives, at fair
value on a recurring basis. SFAS 157 defines a hierarchy for disclosing
fair value measurements based primarily on the level of public data used in
determining fair value. Level 1 inputs include quoted market prices in
active markets for identical assets or liabilities; Level 2 inputs include
inputs other than Level 1 inputs that are directly or indirectly observable; and
Level 3 inputs include unobservable inputs using estimates and assumptions
developed in-house, which reflect what a market participant would use to
determine fair value. At December 31, 2008, other than $40 million
invested in money market funds and included in Cash and cash equivalents,
the Company had no material assets or liabilities recorded at fair value
outstanding and none outstanding valued using Level 3 inputs. The
money market investments are valued using Level 1 inputs. As of
December 31, 2007, the Company had derivatives in Prepayments and other current
assets totaling $2.6 million. In addition, as of December 31,
2007 there was $8.9 million in Accrued liabilities related
to derivatives managing interest rate
risk.
SFAS
159
Also on
January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115” (SFAS 159). SFAS 159 permitted entities to choose
to measure many financial instruments and certain other items at fair
value. The Company did not choose to apply the option provided in
SFAS 159 to any of its eligible items; therefore, its adoption did not have any
impact on the Company’s financial statements or results of
operations.
Fair Value of Other
Financial Instruments
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
||||||||||||||||
|
2008
|
2007
|
|||||||||||||||
|
(In
millions)
|
Carrying
Amount
|
Est.
Fair
Value
|
Carrying
Amount
|
Est.
Fair
Value
|
||||||||||||
|
Long-term
debt
|
$ | 1,189.6 | $ | 1,068.3 | $ | 1,066.2 | $ | 1,049.2 | ||||||||
|
Short-term
borrowings
|
191.9 | 191.9 | 385.9 | 385.9 | ||||||||||||
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.
Under
current regulatory treatment, call premiums on reacquisition of long-term debt
are generally recovered in customer rates over the life of the refunding issue
or over a 15-year period. Accordingly, any reacquisition would not be
expected to have a material effect on the Company's results of
operations.
|
11.
|
Segment
Reporting
|
The
Company’s operations consist of 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. Net income is the measure
of profitability used by management for all operations.
Information
related to the Company’s business segments is summarized below:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
Revenues
|
||||||||||||
|
Gas
Utility Services
|
$ | 1,432.7 | $ | 1,269.4 | $ | 1,232.5 | ||||||
|
Electric
Utility Services
|
524.2 | 487.9 | 422.2 | |||||||||
|
Other
Operations
|
36.8 | 40.4 | 36.6 | |||||||||
|
Eliminations
|
(35.0 | ) | (38.7 | ) | (34.8 | ) | ||||||
|
Total
revenues
|
$ | 1,958.7 | $ | 1,759.0 | $ | 1,656.5 | ||||||
|
Profitability
Measure - Net Income
|
||||||||||||
|
Gas
Utility Services
|
$ | 53.3 | $ | 41.7 | $ | 41.5 | ||||||
|
Electric
Utility Services
|
50.7 | 52.6 | 41.6 | |||||||||
|
Other
Operations
|
7.1 | 12.2 | 8.3 | |||||||||
|
Total
net income
|
$ | 111.1 | $ | 106.5 | $ | 91.4 | ||||||
|
Amounts
Included in Profitability Measures
|
||||||||||||
|
Depreciation &
Amortization
|
||||||||||||
|
Gas
Utility Services
|
$ | 74.1 | $ | 70.6 | $ | 67.6 | ||||||
|
Electric
Utility Services
|
68.5 | 66.0 | 61.8 | |||||||||
|
Other
Operations
|
22.9 | 21.8 | 21.9 | |||||||||
|
Total
depreciation & amortization
|
$ | 165.5 | $ | 158.4 | $ | 151.3 | ||||||
|
Interest
Expense
|
||||||||||||
|
Gas
Utility Services
|
$ | 42.0 | $ | 39.8 | $ | 40.7 | ||||||
|
Electric
Utility Services
|
32.0 | 29.6 | 28.6 | |||||||||
|
Other
Operations
|
5.9 | 11.2 | 8.2 | |||||||||
|
Total
interest expense
|
$ | 79.9 | $ | 80.6 | $ | 77.5 | ||||||
|
Income
Taxes
|
||||||||||||
|
Gas
Utility Services
|
$ | 35.5 | $ | 33.2 | $ | 22.6 | ||||||
|
Electric
Utility Services
|
32.0 | 38.0 | 25.3 | |||||||||
|
Other
Operations
|
0.1 | (4.5 | ) | (0.2 | ) | |||||||
|
Total
income taxes
|
$ | 67.6 | $ | 66.7 | $ | 47.7 | ||||||
|
Capital
Expenditures
|
||||||||||||
|
Gas
Utility Services
|
$ | 110.4 | $ | 128.9 | $ | 76.8 | ||||||
|
Electric
Utility Services
|
172.0 | 134.7 | 156.8 | |||||||||
|
Other
Operations
|
29.6 | 36.4 | 24.8 | |||||||||
|
Non-cash
costs & changes in accruals
|
(5.7 | ) | 2.5 | (8.4 | ) | |||||||
|
Total
capital expenditures
|
$ | 306.3 | $ | 302.5 | $ | 250.0 | ||||||
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Assets
|
||||||||
|
Utility
Group
|
||||||||
|
Gas
Utility Services
|
$ | 2,204.7 | $ | 2,049.1 | ||||
|
Electric
Utility Services
|
1,462.1 | 1,369.2 | ||||||
|
Other
Operations, net of eliminations
|
171.3 | 225.4 | ||||||
|
Total
assets
|
$ | 3,838.1 | $ | 3,643.7 | ||||
|
12.
|
Additional
Balance Sheet & Statement of Income
Information
|
Prepayments and other current
assets in the Consolidated Balance Sheets consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Prepaid
gas delivery service
|
$ | 75.0 | $ | 65.2 | ||||
|
Prepaid
taxes
|
19.3 | 13.6 | ||||||
|
Deferred
income taxes
|
3.1 | - | ||||||
|
Other
prepayments & current assets
|
5.7 | 14.5 | ||||||
|
Total
prepayments & other current assets
|
$ | 103.1 | $ | 93.3 | ||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Refunds
to customers & customer deposits
|
$ | 45.5 | $ | 41.2 | ||||
|
Accrued
taxes
|
45.2 | 32.5 | ||||||
|
Accrued
interest
|
18.0 | 16.1 | ||||||
|
Deferred
income taxes
|
- | 4.9 | ||||||
|
Asset
retirement obligation
|
7.2 | 9.5 | ||||||
|
Accrued
salaries & other
|
31.8 | 34.7 | ||||||
|
Total
accrued liabilities
|
$ | 147.7 | $ | 138.9 | ||||
Other Investments in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2008
|
2007
|
||||||
|
Cash
surrender value of life insurance policies
|
$ | 18.5 | $ | 17.1 | ||||
|
Municipal
bond
|
4.5 | 4.7 | ||||||
|
Restricted
cash
|
- | 1.7 | ||||||
|
Other
investments
|
1.1 | 1.2 | ||||||
|
Total
other investments
|
$ | 24.1 | $ | 24.7 | ||||
Other – net in the
Consolidated Statements of Income consists of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2008
|
2007
|
2006
|
|||||||||
|
AFUDC
& capitalized interest
|
$ | 4.4 | $ | 5.3 | $ | 4.8 | ||||||
|
Interest
income
|
1.0 | 2.3 | 0.7 | |||||||||
|
Cash
surrender value of life insurance policies
|
(2.6 | ) | 0.5 | 0.8 | ||||||||
|
Other
income
|
1.2 | 1.3 | 1.3 | |||||||||
|
Total
other – net
|
$ | 4.0 | $ | 9.4 | $ | 7.6 | ||||||
|
13.
|
Impact
of Recently Issued Accounting
Guidance
|
SFAS 141 (Revised
2007)
In
December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS
141R). SFAS 141R establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141R applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. SFAS 141R applies prospectively to
business combinations with an acquisition date on or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. Early adoption is not permitted. The Company will adopt
SFAS 141R on January 1, 2009, and because the provisions of this standard are
applied prospectively, the impact to the Company cannot be determined until the
transactions occur.
SFAS 161
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS
161). SFAS 161 enhances the current disclosures under SFAS 133 and
requires that objectives for using derivative instruments be disclosed in terms
of underlying risk and accounting designation in order to better convey the
purpose of derivative use in terms of the risks that the entity is intending to
manage. Entities are required to provide enhanced disclosures about
(a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. Tabular disclosure of fair value amounts and gains and
losses on derivative instruments and related hedged items is
required. SFAS 161 is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
adoption encouraged. The Company will adopt SFAS 161 on January 1,
2009, and the impact is not expected to be material to the Company’s financial
position or results of operations.
SFAS 162
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of
accounting principles and the framework for selecting principles used in the
preparation of financial statements. SFAS No. 162 is effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity
with Generally Accepted Accounting Principles”. The implementation of this
standard will not have a material impact on its financial position and results
of operations.
|
14.
|
Subsidiary
Guarantor and Consolidating
Information
|
The
Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of Utility Holdings’ $515 million in short-term credit facilities, of
which $192 million is outstanding at December 31, 2008, and Utility Holdings’
$823 million unsecured senior notes outstanding at December 31,
2008. The guarantees are full and unconditional and joint and
several, and Utility Holdings has no subsidiaries other than the subsidiary
guarantors. However, Utility Holdings does have operations other than
those of the subsidiary guarantors. Pursuant to Item 3-10 of
Regulation S-X, disclosure of the results of operations and balance sheets of
the subsidiary guarantors separate from the parent company’s operations is
required. Following are consolidating financial statements including
information on the combined operations of the subsidiary guarantors separate
from the other operations of the parent company. Pursuant to a tax
sharing agreement, consolidating tax effects, which are calculated on a separate
return basis, are reflected at the parent level.
Consolidating
Statement of Income for the year ended December 31, 2008 (in
millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,432.7 | $ | - | $ | - | $ | 1,432.7 | ||||||||
|
Electric
utility
|
524.2 | - | - | 524.2 | ||||||||||||
| Other | - | 36.8 | (35.0 | ) | 1.8 | |||||||||||
|
Total
operating revenues
|
1,956.9 | 36.8 | (35.0 | ) | 1,958.7 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
983.1 | - | - | 983.1 | ||||||||||||
|
Cost
of fuel & purchased power
|
182.9 | - | - | 182.9 | ||||||||||||
|
Other
operating
|
334.2 | - | (33.9 | ) | 300.3 | |||||||||||
|
Depreciation
& amortization
|
142.3 | 22.9 | 0.3 | 165.5 | ||||||||||||
|
Taxes
other than income taxes
|
70.5 | 1.7 | 0.1 | 72.3 | ||||||||||||
|
Total
operating expenses
|
1,713.0 | 24.6 | (33.5 | ) | 1,704.1 | |||||||||||
|
OPERATING
INCOME
|
243.9 | 12.2 | (1.5 | ) | 254.6 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 104.0 | (104.0 | ) | - | |||||||||||
|
Other
– net
|
1.6 | 52.4 | (50.0 | ) | 4.0 | |||||||||||
|
Total
other income (expense)
|
1.6 | 156.4 | (154.0 | ) | 4.0 | |||||||||||
|
Interest
expense
|
74.0 | 57.4 | (51.5 | ) | 79.9 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
171.5 | 111.2 | (104.0 | ) | 178.7 | |||||||||||
|
Income
taxes
|
67.5 | 0.1 | - | 67.6 | ||||||||||||
|
NET
INCOME
|
$ | 104.0 | $ | 111.1 | $ | (104.0 | ) | $ | 111.1 | |||||||
Consolidating Statement of Income for the year ended December 31, 2007 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,269.4 | $ | - | $ | - | $ | 1,269.4 | ||||||||
|
Electric
utility
|
487.9 | - | - | 487.9 | ||||||||||||
| Other | - | 40.4 | (38.7) | 1.7 | ||||||||||||
|
Total
operating revenues
|
1,757.3 | 40.4 | (38.7 | ) | 1,759.0 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
847.2 | - | - | 847.2 | ||||||||||||
|
Cost
of fuel & purchased power
|
174.8 | - | - | 174.8 | ||||||||||||
|
Other
operating
|
301.5 | - | (35.4 | ) | 266.1 | |||||||||||
|
Depreciation
& amortization
|
136.6 | 21.5 | 0.3 | 158.4 | ||||||||||||
|
Taxes
other than income taxes
|
66.0 | 2.1 | - | 68.1 | ||||||||||||
|
Total
operating expenses
|
1,526.1 | 23.6 | (35.1 | ) | 1,514.6 | |||||||||||
|
OPERATING
INCOME
|
231.2 | 16.8 | (3.6 | ) | 244.4 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 94.3 | (94.3 | ) | - | |||||||||||
|
Other
– net
|
3.7 | 48.3 | (42.6 | ) | 9.4 | |||||||||||
|
Total
other income (expense)
|
3.7 | 142.6 | (136.9 | ) | 9.4 | |||||||||||
|
Interest
expense
|
69.4 | 57.4 | (46.2 | ) | 80.6 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
165.5 | 102.0 | (94.3 | ) | 173.2 | |||||||||||
|
Income
taxes
|
71.2 | (4.5 | ) | - | 66.7 | |||||||||||
|
NET
INCOME
|
$ | 94.3 | $ | 106.5 | $ | (94.3 | ) | $ | 106.5 | |||||||
Consolidating
Statement of Income for the year ended December 31, 2006 (in
millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,232.5 | $ | - | $ | - | $ | 1,232.5 | ||||||||
|
Electric
utility
|
422.2 | - | - | 422.2 | ||||||||||||
| Other | - | 36.6 | (34.8 | ) | 1.8 | |||||||||||
|
Total
operating revenues
|
1,654.7 | 36.6 | (34.8 | ) | 1,656.5 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
841.5 | - | - | 841.5 | ||||||||||||
|
Cost
of fuel & purchased power
|
151.5 | - | - | 151.5 | ||||||||||||
|
Other
operating
|
275.5 | (4.4 | ) | (32.1 | ) | 239.0 | ||||||||||
|
Depreciation
& amortization
|
129.4 | 21.5 | 0.4 | 151.3 | ||||||||||||
|
Taxes
other than income taxes
|
63.0 | 1.1 | 0.1 | 64.2 | ||||||||||||
|
Total
operating expenses
|
1,460.9 | 18.2 | (31.6 | ) | 1,447.5 | |||||||||||
|
OPERATING
INCOME
|
193.8 | 18.4 | (3.2 | ) | 209.0 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 83.2 | (83.2 | ) | - | |||||||||||
|
Other
– net
|
3.7 | 42.6 | (38.7 | ) | 7.6 | |||||||||||
|
Total
other income (expense)
|
3.7 | 125.8 | (121.9 | ) | 7.6 | |||||||||||
|
Interest
expense
|
66.4 | 53.0 | (41.9 | ) | 77.5 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
131.1 | 91.2 | (83.2 | ) | 139.1 | |||||||||||
|
Income
taxes
|
47.9 | (0.2 | ) | - | 47.7 | |||||||||||
|
NET
INCOME
|
$ | 83.2 | $ | 91.4 | $ | (83.2 | ) | $ | 91.4 | |||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2008
(in millions)
Consolidating Statement of Cash Flows for the year ended December 31, 2007 (in millions):
Consolidating Balance Sheet as of December 31, 2007 (in millions):
List of Exhibits
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 379.6 | $ | 55.4 | $ | - | $ | 435.0 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from
|
||||||||||||||||
|
Issuance of
common stock
|
- | 124.8 | - | 124.8 | ||||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
171.1 | 111.1 | (111.1 | ) | 171.1 | |||||||||||
| Requirements for: | ||||||||||||||||
|
Dividends to
parent
|
(83.2 | ) | (83.2 | ) | 83.2 | (83.2 | ) | |||||||||
|
Retirement of
long-term debt, including premiums paid
|
(104.6 | ) | (1.6 | ) | 1.6 | (104.6 | ) | |||||||||
|
Net change in
intercompany short-term borrowings
|
(80.9 | ) | 103.9 | (23.0 | ) | - | ||||||||||
|
Net change in
short-term borrowings
|
0.4 | (194.4 | ) | - | (194.0 | ) | ||||||||||
|
Net
cash flows from financing activities
|
(97.2 | ) | 60.6 | (49.3 | ) | (85.9 | ) | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from
|
||||||||||||||||
|
Consolidated
subsidiary distributions
|
- | 83.2 | (83.2 | ) | - | |||||||||||
|
Other
investing activities
|
2.3 | 0.2 | - | 2.5 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(277.0 | ) | (29.3 | ) | - | (306.3 | ) | |||||||||
|
Other
investing activities
|
(4.5 | ) | - | - | (4.5 | ) | ||||||||||
|
Net change in
long-term intercompany notes receivable
|
- | (109.5 | ) | 109.5 | - | |||||||||||
|
Net change in
short-term intercompany notes receivable
|
- | (23.0 | ) | 23.0 | - | |||||||||||
|
Net
cash flows from investing activities
|
(279.2 | ) | (78.4 | ) | 49.3 | (308.3 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
3.2 | 37.6 | - | 40.8 | ||||||||||||
|
Cash
& cash equivalents at beginning of period
|
6.5 | 5.2 | - | 11.7 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2007 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 211.2 | $ | 21.0 | $ | - | $ | 232.2 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
30.3 | - | (14.0 | ) | 16.3 | |||||||||||
|
Additional
capital contribution
|
- | 5.3 | - | 5.3 | ||||||||||||
|
Requirements
for:
|
||||||||||||||||
|
Dividends to
parent
|
(76.4 | ) | (76.6 | ) | 76.4 | (76.6 | ) | |||||||||
|
Retirement of
long-term debt, including premiums paid
|
(6.5 | ) | - | - | (6.5 | ) | ||||||||||
|
Net change in short-term borrowings, including from other
|
||||||||||||||||
|
Vectren
companies
|
110.3 | 115.8 | (110.3 | ) | 115.8 | |||||||||||
| Other activity | - | - | - | - | ||||||||||||
|
Net
cash flows from financing activities
|
57.7 | 44.5 | (47.9 | ) | 54.3 | |||||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from:
|
||||||||||||||||
|
Consolidated
subsidiary distributions
|
- | 76.4 | (76.4 | ) | - | |||||||||||
|
Other
investing activities
|
0.7 | 0.3 | - | 1.0 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(267.0 | ) | (35.5 | ) | - | (302.5 | ) | |||||||||
|
Consolidated
subsidiary investments
|
- | (14.0 | ) | 14.0 | - | |||||||||||
|
Unconsolidated
affiliate & other investments
|
(1.8 | ) | - | - | (1.8 | ) | ||||||||||
|
Net change in notes receivable from other Vectren
companies
|
- | (110.3 | ) | 110.3 | - | |||||||||||
|
Net
cash flows from investing activities
|
(268.1 | ) | (83.1 | ) | 47.9 | (303.3 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
0.8 | (17.6 | ) | - | (16.8 | ) | ||||||||||
|
Cash
& cash equivalents at beginning of period
|
5.7 | 22.8 | - | 28.5 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 6.5 | $ | 5.2 | $ | - | $ | 11.7 | ||||||||
Consolidating
Statement of Cash Flows for the year ended December 31, 2006 (in
millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 279.9 | $ | 6.2 | $ | - | $ | 286.1 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
228.9 | 92.8 | (228.9 | ) | 92.8 | |||||||||||
|
Additional
capital contribution
|
40.0 | 20.0 | (40.0 | ) | 20.0 | |||||||||||
|
Requirements
for:
|
||||||||||||||||
|
Dividends to
parent
|
(75.4 | ) | (75.4 | ) | 75.4 | (75.4 | ) | |||||||||
|
Retirement of
long-term debt, including premiums paid
|
(96.7 | ) | (100.0 | ) | 96.7 | (100.0 | ) | |||||||||
|
Net change in short-term borrowings, including from other
|
||||||||||||||||
|
Vectren
companies
|
(156.5 | ) | 43.2 | 156.5 | 43.2 | |||||||||||
|
Net
cash flows from financing activities
|
(59.7 | ) | (19.4 | ) | 59.7 | (19.4 | ) | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from:
|
||||||||||||||||
|
Consolidated
subsidiary distributions
|
- | 75.4 | (75.4 | ) | - | |||||||||||
|
Other
investing activities
|
- | 0.1 | - | 0.1 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(225.5 | ) | (24.5 | ) | - | (250.0 | ) | |||||||||
|
Consolidated
subsidiary investments
|
- | (172.2 | ) | 172.2 | - | |||||||||||
|
Net change in notes receivable from other Vectren
companies
|
- | 156.5 | (156.5 | ) | - | |||||||||||
|
Net
cash flows from investing activities
|
(225.5 | ) | 35.3 | (59.7 | ) | (249.9 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
(5.3 | ) | 22.1 | - | 16.8 | |||||||||||
|
Cash
& cash equivalents at beginning of period
|
11.0 | 0.7 | - | 11.7 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 5.7 | $ | 22.8 | $ | - | $ | 28.5 | ||||||||
Consolidating Balance Sheet as of December 31, 2008 (in
millions)
|
ASSETS
|
||||||||||||||||
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Assets
|
||||||||||||||||
|
Cash & cash
equivalents
|
$ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
|
Accounts receivable -
less reserves
|
163.5 | 0.5 | - | 164.0 | ||||||||||||
|
Intercompany
receivables
|
104.2 | 275.9 | (380.1 | ) | - | |||||||||||
|
Receivables due from
other Vectren companies
|
4.5 | 0.2 | - | 4.7 | ||||||||||||
|
Accrued unbilled
revenues
|
167.2 | - | - | 167.2 | ||||||||||||
|
Inventories
|
78.7 | 5.9 | - | 84.6 | ||||||||||||
|
Recoverable fuel &
natural gas costs
|
3.1 | - | - | 3.1 | ||||||||||||
|
Prepayments & other
current assets
|
82.9 | 38.5 | (18.3 | ) | 103.1 | |||||||||||
|
Total
current assets
|
613.8 | 363.8 | (398.4 | ) | 579.2 | |||||||||||
|
Utility
Plant
|
||||||||||||||||
|
Original
cost
|
4,335.3 | - | - | 4,335.3 | ||||||||||||
|
Less: accumulated
depreciation & amortization
|
1,615.0 | - | - | 1,615.0 | ||||||||||||
|
Net
utility plant
|
2,720.3 | - | - | 2,720.3 | ||||||||||||
|
Investments
in consolidated subsidiaries
|
- | 1,167.4 | (1,167.4 | ) | - | |||||||||||
|
Notes
receivable from consolidated subsidiaries
|
- | 698.9 | (698.9 | ) | - | |||||||||||
|
Investments
in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other
investments
|
18.5 | 5.6 | - | 24.1 | ||||||||||||
|
Nonutility
property - net
|
4.3 | 178.1 | - | 182.4 | ||||||||||||
|
Goodwill
- net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory
assets
|
90.5 | 25.2 | - | 115.7 | ||||||||||||
|
Other
assets
|
14.2 | 0.2 | (3.2 | ) | 11.2 | |||||||||||
|
TOTAL
ASSETS
|
$ | 3,666.8 | $ | 2,439.2 | $ | (2,267.9 | ) | $ | 3,838.1 | |||||||
|
LIABILITIES & SHAREHOLDER'S
EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Liabilities
|
||||||||||||||||
|
Accounts
payable
|
$ | 205.5 | $ | 7.0 | $ | - | $ | 212.5 | ||||||||
|
Accounts
payable to affiliated companies
|
72.8 | - | - | 72.8 | ||||||||||||
|
Intercompany
payables
|
9.5 | 0.4 | (9.9 | ) | - | |||||||||||
|
Payables to other Vectren companies
|
53.6 | 15.4 | - | 69.0 | ||||||||||||
|
Refundable
fuel & natural gas costs
|
4.1 | - | - | 4.1 | ||||||||||||
|
Accrued
liabilities
|
146.4 | 19.6 | (18.3 | ) | 147.7 | |||||||||||
|
Short-term
borrowings
|
0.4 | 191.5 | - | 191.9 | ||||||||||||
|
Intercompany
short-term borrowings
|
266.3 | 103.9 | (370.2 | ) | - | |||||||||||
|
Long-term
debt subject to tender
|
80.0 | - | - | 80.0 | ||||||||||||
|
Total
current liabilities
|
838.6 | 337.8 | (398.4 | ) | 778.0 | |||||||||||
|
Long-Term
Debt
|
||||||||||||||||
|
Long-term debt - net of current maturities &
|
||||||||||||||||
|
debt
subject to tender
|
243.1 | 822.0 | - | 1,065.1 | ||||||||||||
|
Long-term debt due to VUHI
|
698.9 | - | (698.9 | ) | - | |||||||||||
|
Total
long-term debt - net
|
942.0 | 822.0 | (698.9 | ) | 1,065.1 | |||||||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred income taxes
|
308.9 | 23.2 | - | 332.1 | ||||||||||||
|
Regulatory liabilities
|
310.4 | 4.7 | - | 315.1 | ||||||||||||
|
Deferred credits & other liabilities
|
99.5 | 8.6 | (3.2 | ) | 104.9 | |||||||||||
|
Total
deferred credits & other liabilities
|
718.8 | 36.5 | (3.2 | ) | 752.1 | |||||||||||
|
Common
Shareholder's Equity
|
||||||||||||||||
|
Common stock (no par value)
|
776.3 | 763.0 | (776.3 | ) | 763.0 | |||||||||||
|
Retained earnings
|
391.0 | 479.8 | (391.0 | ) | 479.8 | |||||||||||
|
Accumulated other comprehensive income
|
0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
|
Total
common shareholder's equity
|
1,167.4 | 1,242.9 | (1,167.4 | ) | 1,242.9 | |||||||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,666.8 | $ | 2,439.2 | $ | (2,267.9 | ) | $ | 3,838.1 | |||||||
Consolidating Balance Sheet as of December 31, 2007 (in millions):
|
ASSETS
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Assets
|
||||||||||||||||
|
Cash
& cash equivalents
|
$ | 6.5 | $ | 5.2 | $ | - | $ | 11.7 | ||||||||
|
Accounts
receivable - less reserves
|
136.3 | 0.8 | - | 137.1 | ||||||||||||
|
Receivables
due from other Vectren companies
|
0.1 | 276.6 | (258.8 | ) | 17.9 | |||||||||||
|
Accrued
unbilled revenues
|
140.6 | - | - | 140.6 | ||||||||||||
|
Inventories
|
133.8 | 1.1 | - | 134.9 | ||||||||||||
|
Recoverable
fuel & natural gas costs
|
- | - | - | - | ||||||||||||
|
Prepayments
& other current assets
|
87.3 | 10.5 | (4.5 | ) | 93.3 | |||||||||||
|
Total
current assets
|
504.6 | 294.2 | (263.3 | ) | 535.5 | |||||||||||
|
Utility
Plant
|
||||||||||||||||
|
Original
cost
|
4,062.9 | - | - | 4,062.9 | ||||||||||||
|
Less: accumulated
depreciation & amortization
|
1,523.2 | - | - | 1,523.2 | ||||||||||||
|
Net
utility plant
|
2,539.7 | - | - | 2,539.7 | ||||||||||||
|
Investments
in consolidated subsidiaries
|
- | 1,147.0 | (1,147.0 | ) | - | |||||||||||
|
Notes
receivable from consolidated subsidiaries
|
- | 589.4 | (589.4 | ) | - | |||||||||||
|
Investments
in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other
investments
|
18.9 | 5.8 | - | 24.7 | ||||||||||||
|
Nonutility
property - net
|
4.8 | 171.4 | - | 176.2 | ||||||||||||
|
Goodwill
- net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory
assets
|
130.3 | 21.4 | - | 151.7 | ||||||||||||
|
Other
assets
|
14.8 | 0.5 | (4.6 | ) | 10.7 | |||||||||||
|
TOTAL
ASSETS
|
$ | 3,418.3 | $ | 2,229.7 | $ | (2,004.3 | ) | $ | 3,643.7 | |||||||
|
LIABILITIES & SHAREHOLDER'S
EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Liabilities
|
||||||||||||||||
|
Accounts
payable
|
$ | 132.6 | $ | 6.1 | $ | - | $ | 138.7 | ||||||||
|
Accounts
payable to affiliated companies
|
66.9 | - | - | 66.9 | ||||||||||||
|
Payables
to other Vectren companies
|
49.6 | 0.1 | (15.5 | ) | 34.2 | |||||||||||
|
Refundable
fuel & natural gas costs
|
27.2 | - | - | 27.2 | ||||||||||||
|
Accrued
liabilities
|
123.4 | 20.0 | (4.5 | ) | 138.9 | |||||||||||
|
Short-term
borrowings
|
- | 385.9 | - | 385.9 | ||||||||||||
|
Short-term
borrowings from
|
||||||||||||||||
|
other
Vectren companies
|
243.3 | - | (243.3 | ) | - | |||||||||||
|
Current
maturities of long-term debt
|
- | - | - | - | ||||||||||||
|
Long-term
debt subject to tender
|
- | - | - | - | ||||||||||||
|
Total
current liabilities
|
643.0 | 412.1 | (263.3 | ) | 791.8 | |||||||||||
|
Long-Term
Debt
|
||||||||||||||||
|
Long-term
debt - net of current maturities &
|
||||||||||||||||
|
debt
subject to tender
|
364.2 | 698.4 | - | 1,062.6 | ||||||||||||
|
Long-term
debt due to VUHI
|
589.4 | - | (589.4 | ) | - | |||||||||||
|
Total
long-term debt - net
|
953.6 | 698.4 | (589.4 | ) | 1,062.6 | |||||||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred
income taxes
|
270.0 | 16.9 | - | 286.9 | ||||||||||||
|
Regulatory
liabilities
|
301.8 | 5.4 | - | 307.2 | ||||||||||||
|
Deferred
credits & other liabilities
|
102.9 | 6.5 | (4.6 | ) | 104.8 | |||||||||||
|
Total
deferred credits & other liabilities
|
674.7 | 28.8 | (4.6 | ) | 698.9 | |||||||||||
|
Common
Shareholder's Equity
|
||||||||||||||||
|
Common
stock (no par value)
|
776.3 | 638.2 | (776.3 | ) | 638.2 | |||||||||||
|
Retained
earnings
|
370.4 | 451.9 | (370.4 | ) | 451.9 | |||||||||||
|
Accumulated
other comprehensive income
|
0.3 | 0.3 | (0.3 | ) | 0.3 | |||||||||||
|
Total
common shareholder's equity
|
1,147.0 | 1,090.4 | (1,147.0 | ) | 1,090.4 | |||||||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,418.3 | $ | 2,229.7 | $ | (2,004.3 | ) | $ | 3,643.7 | |||||||
|
15.
|
Quarterly
Financial Data (Unaudited)
|
Information
in any one quarterly period is not indicative of annual results due to the
seasonal variations common to the Company’s utility
operations. Summarized quarterly financial data for 2008 and 2007
follows:
|
(In
millions)
|
Q1 | Q2 | Q3 | Q4 | ||||||||||||
|
2008
|
||||||||||||||||
|
Results
of Operations:
|
||||||||||||||||
|
Operating
revenues
|
$ | 761.4 | $ | 352.7 | $ | 292.4 | $ | 552.2 | ||||||||
|
Operating
income
|
112.5 | 31.1 | 41.0 | 70.0 | ||||||||||||
|
Net
income
|
58.0 | 8.8 | 13.6 | 30.7 | ||||||||||||
|
2007
|
||||||||||||||||
|
Results
of Operations:
|
||||||||||||||||
|
Operating
revenues
|
$ | 692.6 | $ | 302.3 | $ | 258.0 | $ | 506.1 | ||||||||
|
Operating
income
|
96.9 | 29.8 | 37.3 | 80.4 | ||||||||||||
|
Net
income
|
50.9 | 8.0 | 10.7 | 36.9 | ||||||||||||
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Changes in Internal Controls
over Financial Reporting
During
the quarter ended December 31, 2008, there have been no changes to the Company’s
internal controls over financial reporting that have materially affected, or are
reasonably likely to materially affect, the Company’s internal control over
financial reporting.
Conclusion Regarding the
Effectiveness of Disclosure Controls and Procedures
As of
December 31, 2008, the Company conducted an evaluation under the supervision and
with the participation of the Chief Executive Officer and Chief Financial
Officer of the effectiveness and the design and operation of the Company's
disclosure controls and procedures. Based on that evaluation, the
Chief Executive Officer and the Chief Financial Officer have concluded that the
Company's disclosure controls and procedures are effective as of December 31,
2008, to ensure that information required to be disclosed in reports filed or
submitted under the Exchange Act is:
|
1)
|
recorded,
processed, summarized and reported within the time periods specified in
the SEC’s rules and forms, and
|
|
|
2)
|
accumulated
and communicated to management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
|
Management’s Report on
Internal Control over Financial Reporting
Vectren
Utility Holdings, Inc.’s management is responsible for establishing and
maintaining adequate internal control over financial reporting. Under
the supervision and with the participation of management, including the Chief
Executive Officer and Chief Financial Officer, the Company conducted an
evaluation of the effectiveness of its internal control over financial reporting
based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on that evaluation under the framework in
Internal Control — Integrated
Framework, the Company concluded that its internal control over financial
reporting was effective as of December 31, 2008.
This
annual report does not include an attestation report of Utility Holdings’
registered public accounting firm regarding internal control over financial
reporting. Management's report was not subject to attestation by
Utility Holdings’ registered public accounting firm pursuant to temporary rules
of the Securities and Exchange Commission that permit Utility Holdings to
provide only management's report in this annual report.
ITEM 9B. OTHER INFORMATION
None.
PART
III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
Vectren’s
Corporate Governance Guidelines, its charters for each of its Audit,
Compensation and Benefits and Nominating and Corporate Governance Committees,
and its Code of Ethics covering the Company’s directors, officers and employees
are available on the Company’s website, www.vectren.com, and a copy
will be mailed upon request to Investor Relations, Attention: Steve Schein, One
Vectren Square, Evansville, Indiana 47708. Vectren intends to
disclose any amendments to the Code of Ethics or waivers of the Code of Ethics
on behalf of the Vectren’s directors or officers including, but not limited to,
the principal executive officer, principal financial officer, principal
accounting officer or controller and persons performing similar functions on
Vectren’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
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
ITEM
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AND DIRECTOR INDEPENDENCE
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
The
following tabulation shows the audit and non-audit fees incurred and payable to
Deloitte & Touche LLP (Deloitte) for the years ending December 31, 2008 and
2007. The fees presented below represent total Vectren fees, the
majority of which are allocated to Utility Holdings.
|
2008
|
2007
|
|||||||
|
Audit
Fees(1)
|
$ | 1,378,911 | $ | 1,157,989 | ||||
|
Audit-Related
Fees(2)
|
235,449 | 258,795 | ||||||
|
Tax
Fees(3)
|
162,073 | 242,219 | ||||||
|
Total
Fees Paid to Deloitte(4)
|
$ | 1,776,433 | $ | 1,659,003 | ||||
|
(1)
|
Aggregate
fees incurred and payable to Deloitte for professional services rendered
for the audits of Vectren’s and Utility Holdings’ 2008 and 2007
fiscal year annual financial statements and the review of financial
statements included in their Forms 10-K or 10-Q filed during the Company’s
2008 and 2007 fiscal years. The amount includes fees related to
the attestation to Vectren’s assertion pursuant to Section 404 of the
Sarbanes-Oxley Act of 2002. In addition, this amount includes
the reimbursement of out-of-pocket costs incurred related to the provision
of these services totaling $69,911 and $83,989 in 2008 and 2007,
respectively.
|
|
(2)
|
Audit-related
fees consisted principally of reviews related to various financing
transactions, regulatory filings, consultation on various accounting
issues, and audit fees related to the stand-alone audit of one of
Vectren’s consolidated
subsidiaries.
|
|
(3)
|
Tax
fees consisted of fees paid to Deloitte for the review of tax returns,
consultation on other tax matters of Vectren and of its consolidated
subsidiaries, and tax technical training. In addition, this
amount includes the reimbursement of out-of-pocket costs incurred related
to the provision of these services totaling $17,548 and $20,426 in 2008
and 2007, respectively.
|
|
(4)
|
Pursuant
to its charter, the Audit committee of Vectren Corporation is responsible
for selecting, approving professional fees and overseeing the
independence, qualifications and performance of the independent registered
public accounting firm. The Audit committee has adopted a
formal policy with respect to the pre-approval of audit and permissible
non-audit services provided by the independent registered public
accounting firm. Pre-approval is assessed on a case-by-case
basis. In assessing requests for services to be provided by the
independent registered public accounting firm, the Audit committee
considers whether such services are consistent with the auditors’
independence, whether the independent registered public accounting firm is
likely to provide the most effective and efficient service based upon the
firm’s familiarity with Vectren and Utility Holdings, and whether the
service could enhance the Company’s ability to manage or control risk or
improve audit quality. The audit-related, tax and other
services provided by Deloitte in the last year and related fees were
approved by the Audit committee of Vectren Corporation in accordance with
this policy.
|
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.
Supplemental
Schedules
For the
years ended December 31, 2008, 2007, and 2006, the Company’s Schedule II --
Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is
presented herein. The report of Deloitte & Touche LLP on the
schedule may be found in Item 8. All other schedules are omitted as
the required information is inapplicable or the information is presented in the
Consolidated Financial Statements or related notes in Item 8.
SCHEDULE
II
Vectren
Utility Holdings, Inc. and Subsidiaries
VALUATION
AND QUALIFYING ACCOUNTS AND RESERVES
|
Column
A
|
Column
B
|
Column
C
|
Column
D
|
Column
E
|
||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Balance
at
|
Charged
|
Charged
|
Deductions
|
Balance
at
|
||||||||||||||||
|
Beginning
|
to
|
to
Other
|
from
|
End
of
|
||||||||||||||||
|
Description
|
Of
Year
|
Expenses
|
Accounts
|
Reserves,
Net
|
Year
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
VALUATION
AND QUALIFYING ACCOUNTS:
|
||||||||||||||||||||
|
Year
2008 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 2.7 | $ | 15.8 | $ | - | $ | 14.0 | $ | 4.5 | ||||||||||
|
Year
2007 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 2.5 | $ | 15.0 | $ | - | $ | 14.8 | $ | 2.7 | ||||||||||
|
Year
2006 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 2.6 | $ | 13.6 | $ | - | $ | 13.7 | $ | 2.5 | ||||||||||
|
OTHER
RESERVES:
|
||||||||||||||||||||
|
Year
2008 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | - | $ | 0.6 | ||||||||||
|
Year
2007 – Restructuring costs
|
$ | 1.7 | $ | - | $ | - | $ | 1.1 | $ | 0.6 | ||||||||||
|
Year
2006 – Restructuring costs
|
$ | 2.4 | $ | - | $ | - | $ | 0.7 | $ | 1.7 | ||||||||||
List of Exhibits
The
Company has incorporated by reference herein certain exhibits as specified below
pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the
Company attached to this filing filed electronically with the SEC are listed
below.
Vectren
Utility Holdings, Inc.
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
|
|
12
|
|
|
21.1
|
|
|
23.1
|
|
INDEX
TO EXHIBITS
3. Articles of
Incorporation and By-Laws
|
3.1
|
Articles
of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated
in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as
Exhibit 3.1)
|
|
3.2
|
Bylaws
of Vectren Utility Holdings, Inc. (Filed and designated in Registration
Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit
3.2)
|
4. Instruments
Defining the Rights of Security Holders, Including
Indentures
|
4.1
|
Mortgage
and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas
and Electric Company and Bankers Trust Company, as Trustee, and
Supplemental Indentures thereto dated August 31, 1936, October 1, 1937,
March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1,
1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966,
August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1,
1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981,
January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November
1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed
and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in
Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit
(b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K,
File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated
March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3,
1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed
and designated in Form 10-K, for the fiscal year 1985, File
No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January
15, 1987. (Filed and designated in Form 10-K, for the fiscal
year 1986, File No. 1-3553, as Exhibit 4-A.) December 15,
1987. (Filed and designated in Form 10-K, for the fiscal year
1987, File No. 1-3553, as Exhibit 4-A.) December 13,
1990. (Filed and designated in Form 10-K, for the fiscal year
1990, File No. 1-3553, as Exhibit 4-A.) April 1,
1993. (Filed and designated in Form 8-K, dated April 13, 1993,
File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and
designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit
4.) May 1, 1993. (Filed and designated in Form 10-K,
for the fiscal year 1993, File No. 1-3553, as Exhibit
4(a).) July 1, 1999. (Filed and designated in Form
10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit
4(a).) March 1, 2000. (Filed and designated in Form
10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit
4.1.) August 1, 2004. (Filed and designated in Form 10-K for
the year ended December 31, 2004, File No. 1-15467, as Exhibit
4.1.) October 1, 2004. (Filed and designated in Form
10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit
4.2.) April 1, 2005 (Filed and designated in Form 10-K for the
year ended December 31, 2007, File No 1-15467, as Exhibit
4.1) March 1, 2006 (Filed and designated in Form 10-K for the
year ended December 31, 2007, File No 1-15467, as Exhibit
4.2) December 1, 2007 (Filed and designated in Form 10-K for
the year ended December 31, 2007, File No 1-15467, as Exhibit
4.3)
|
|
4.2
|
Indenture
dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National
Association (formerly know as First Trust National Association, which was
formerly know as Bank of America Illinois, which was formerly know as
Continental Bank, National Association. Inc.'s. (Filed and
designated in Current Report on Form 8-K filed February 15, 1991, File No.
1-6494.); First Supplemental Indenture thereto dated as of February 15,
1991. (Filed and designated in Current Report on Form 8-K filed
February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental
Indenture thereto dated as of September 15, 1991, (Filed and designated in
Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as
Exhibit 4(b).); Third supplemental Indenture thereto dated as of September
15, 1991 (Filed and designated in Current Report on Form 8-K filed
September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth
Supplemental Indenture thereto dated as of December 2, 1992, (Filed and
designated in Current Report on Form 8-K filed December 8, 1992, File No.
1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as
of December 28, 2000, (Filed and designated in Current Report on Form 8-K
filed December 27, 2000, File No. 1-6494, as Exhibit
4.)
|
|
4.3
|
Indenture
dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association.
(Filed and designated in Form 8-K, dated October 19, 2001, File No.
1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19,
2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery of
Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental
Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery
of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit
4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated November 18,
2005, File No. 1-16739, as Exhibit 4.1). Form of Fifth
Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas & Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated October 16, 2006, File No. 1-16739, as
Exhibit 4.1). Sixth Supplemental Indenture, dated March 10,
2008, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery of
Ohio, Inc., and U.S. Bank National Association (Filed and designated in
Form 8-K, dated March 10, 2008, File No. 1-16739, as Exhibit
4.1)
|
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 stock unit award agreement
for non-employee members of the Board of Directors, effective January 1,
2009. (Filed and designated in Form 8-K, dated February 20,
2009, File No. 1-15467, as Exhibit
10.1.)
|
|
10.10
|
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.)
|
|
10.11
|
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 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.
|
|
10.16
|
Life
Insurance Replacement Agreement between Vectren Corporation and certain
named officers, effective December 31, 2006. (Filed and
designated in Form 8-K, dated December 31, 2006, File No. 1-15467 as
Exhibit 99.1.)
|
|
10.17
|
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
|
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.)
|
|
10.22
|
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.)
|
|
10.23
|
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.)
|
|
10.24
|
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among Vectren
Utility Holdings, Inc., and each of the purchasers named
therein. (Filed and designated in Form 10-K, for the year ended
December 31, 2005, File No. 1-15467, as Exhibit
10.24.)
|
The list
of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.
(Filed
herewith.)
The
consent of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 (Filed
herewith.)
31.
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
99.
Additional Exhibits
|
99.1
|
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.)
|
|
99.2
|
Amended
and Restated Code of By-Laws of Vectren Corporation as of February 27,
2008. (Filed and designated in Current Report on Form 8-K filed February
27, 2008, File No. 1-15467, as Exhibit
3.1.)
|
|
99.3
|
Shareholders
Rights Agreement dated as of October 21, 1999 between Vectren Corporation
and Equiserve Trust Company, N.A., as Rights Agent. (Filed and
designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No.
1-15467, as Exhibit 4.)
|
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
UTILITY HOLDINGS, INC.
Dated: March
2,
2009
/s/ Niel C.
Ellerbrook
Niel C.
Ellerbrook,
Chairman,
Chief Executive Officer and Director
Pursuant
to the requirements of the Securities and Exchange Act of 1934, this report has
been signed below by the following persons on behalf of the Registrant and in
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||
|
/s/
Niel C. Ellerbrook
|
Chairman,
Chief Executive Officer and Director
|
March
2, 2009
|
||
|
Niel
C. Ellerbrook
|
(Principal
Executive Officer)
|
|||
|
/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President and Chief Financial Officer
|
March
2, 2009
|
||
|
Jerome
A. Benkert, Jr.
|
(Principal
Financial Officer)
|
|||
|
/s/ M.
Susan Hardwick
|
Vice
President, Controller and Assistant Treasurer
|
March
2, 2009
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
|
/s/
Ronald E. Christian
|
Director
|
March
2, 2009
|
||
|
Ronald
E. Christian
|
||||
|
/s/
William S. Doty
|
Director
|
March
2, 2009
|
||
|
William
S. Doty
|
80