UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
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ý
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the fiscal year ended December 31, 2007
OR
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
transition period from __________________ to
________________________
Commission
file number: 1-16739
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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, Evansville, Indiana
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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, 2007, 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,
2008
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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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NOx: nitrogen
oxide
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FERC: Federal
Energy Regulatory Commission
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OUCC: Indiana
Office of the Utility Consumer Counselor
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IDEM: Indiana
Department of Environmental Management
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PUCO: Public
Utilities Commission of Ohio
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IURC: Indiana
Utility Regulatory Commission
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SFAS: Statement
of Financial Accounting Standards
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MCF
/ BCF: thousands / billions of cubic feet
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USEPA: United
States Environmental Protection Agency
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MDth
/ MMDth: thousands / millions of dekatherms
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Throughput: combined
gas sales and gas transportation
volumes
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Access
to Information
Vectren
Corporation makes available all SEC filings and recent annual reports, including
those of Vectren Utility Holdings, Inc., free of charge through its website at
www.vectren.com, or by request, directed to Investor Relations at the mailing
address, phone number, or email address that follows:
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Mailing
Address:
One
Vectren Square
Evansville,
Indiana 47708
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Phone
Number:
(812)
491-4000
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Investor
Relations Contact:
Steven
M. Schein
Vice
President, Investor Relations
sschein@vectren.com
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Table
of Contents
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Item
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Page
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Number
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Number
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Part
I
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||||||
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1
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Business
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5
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1A
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Risk
Factors
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9
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1B
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Unresolved
Staff Comments
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13
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2
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Properties
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13
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3
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Legal
Proceedings
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14
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4
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Submission
of Matters to Vote of Security Holders
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14
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Part
II
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5
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Market
for the Company’s Common Equity, Related Stockholder Matters,
and Issuer Purchases of Equity Securities
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14
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6
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Selected
Financial Data
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15
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7
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Management's
Discussion and Analysis of Results of Operations and Financial
Condition
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15
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7A
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Qualitative
and Quantitative Disclosures About Market Risk
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34
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8
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Financial
Statements and Supplementary Data
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36
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9
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Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
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71
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9A
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Controls
and Procedures, including Management’s Assessment of Internal Controls
over Financial ReportingControls and Procedures
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71
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9B
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Other
Information
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71
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Part
III
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10
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Directors,
Executive Officers and Corporate Governance(A)
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71
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11
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Executive
Compensation(A)
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72
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12
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters(A)
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72
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13
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Certain
Relationships, Related Transactions and Director Independence(A)
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72
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14
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Principal
Accountant Fees and Services
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72
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Part
IV
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15
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Exhibits
and Financial Statement Schedules
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73
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Signatures
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78
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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 112,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and
SIGECO generally do business as Vectren Energy Delivery of
Indiana. The Ohio operations provide energy delivery services to
approximately 318,000 natural gas customers located near Dayton in west central
Ohio. The Ohio operations are owned as a tenancy in common by Vectren
Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility
Holdings (53 percent ownership), and Indiana Gas (47 percent
ownership). The Ohio operations generally do business as Vectren
Energy Delivery of Ohio.
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 operating segment
and an Electric Utility Services operating segment. The Gas Utility
Services segment includes the operations of Indiana Gas, the Ohio operations,
and SIGECO’s natural gas distribution business and provides natural gas
distribution and transportation services to nearly two-thirds of Indiana and to
west central Ohio. The Electric Utility Services segment includes the
operations of SIGECO’s electric transmission and distribution services, which
provides electric distribution services primarily to southwestern Indiana, and
includes the Company’s power generating and asset optimization
operations. In total, these regulated operations supply natural gas
and/or electricity to over one million customers.
At
December 31, 2007, the Company had $3.6 billion in total assets, with $2.0
billion (56 percent) attributed to Gas Utility Services, $1.4 billion (38
percent) attributed to Electric Utility Services, and $0.2 billion (6 percent)
attributed to Other Operations. Net income for the year ended
December 31, 2007, was $106.5 million, with $41.7 million attributed to the Gas
Utility Services, $52.6 million attributed to Electric Utility Services, and
$12.2 million attributed to Other Operations. Net income for the year
ended December 31, 2006, was $91.4 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, 2007, the Company supplied natural gas service to approximately
998,000 Indiana and Ohio customers, including 911,000 residential, 85,000
commercial, and 2,000 industrial and other contract customers. This
represents customer base growth of 0.3 percent compared to 2006.
The
Company’s service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served
include automotive assembly, parts and accessories, feed, flour and grain
processing, metal castings, aluminum products, appliance manufacturing,
polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical
equipment, metal specialties, glass, steel finishing, pharmaceutical and
nutritional products, gasoline and oil products, and coal mining. The
largest Indiana communities served are Evansville, Bloomington, Terre Haute, and
suburban areas surrounding Indianapolis and Indiana counties near Louisville,
Kentucky. The largest community served outside of Indiana is Dayton,
Ohio.
Revenues
For the
year ended December 31, 2007, gas utility revenues were approximately $1,269.4
million, of which residential customers accounted for 67 percent, commercial 27
percent, and industrial and other contract customers 6 percent.
The
Company receives gas revenues by selling gas directly to customers at approved
rates or by transporting gas through its pipelines at approved rates to
customers that have purchased gas directly from other producers, brokers, or
marketers. Total volumes of gas provided to both sales and
transportation customers (throughput) were 194.6 MMDth for the year ended
December 31, 2007. Gas transported or sold to residential and
commercial customers was 108.4 MMDth representing 56 percent of
throughput. Gas transported or sold to industrial and other contract
customers was 86.2 MMDth representing 44 percent of throughput. Rates
for transporting gas generally provide for the same margins earned by selling
gas under applicable sales tariffs.
The
volume of gas sold is seasonal and affected by variations in weather
conditions. To mitigate seasonal demand, the Company has storage
capacity at seven active underground gas storage fields and six liquefied
petroleum air-gas manufacturing plants. The Company also contracts
with its affiliate, ProLiance Holdings, LLC (ProLiance), and with other third
party gas service providers to ensure availability of gas. ProLiance
is an unconsolidated, nonutility, energy marketing affiliate of Vectren and
Citizens Gas and Coke Utility (Citizens Gas). (See Note 4 in the
Company’s Consolidated Financial Statements included in “Item 8 Financial
Statements and Supplementary Data” regarding transactions with
ProLiance). Periodically, purchased natural gas is injected into
storage. The injected gas is then available to supplement contracted
and manufactured volumes during periods of peak requirements. The
Company also prepays ProLiance for natural gas delivery services during the
seven months prior to the peak heating season. The volumes of gas per
day that can be delivered during peak demand periods for each utility are
located in “Item 2 Properties.”
Gas
Purchases
In 2007,
the Company purchased 101,912 MDth volumes of gas at an average cost of $8.14
per Dth, of which approximately 71 percent was purchased through ProLiance and
29 percent was purchased from third party providers. Vectren received
regulatory approval on April 25, 2006 from the IURC for ProLiance to provide
natural gas supply services to the Company’s Indiana utilities through March
2011. As a result of a June 2005 PUCO order, the Company has
established an annual bidding process for VEDO’s gas supply and portfolio
administration services. Since November 1, 2005, the Company has used
a third party provider for these services. Prior to October 31, 2005,
ProLiance supplied natural gas to all of the Company’s regulated gas
utilities. The average cost of gas per Dth purchased for the previous
five years was $8.14 in 2007, $8.64 in 2006, $9.05 in 2005, $6.92 in 2004, and
$6.36 in 2003.
Electric Utility
Services
At
December 31, 2007, the Company supplied electric service to over 141,000 Indiana
customers, including approximately 122,000 residential, 18,800 commercial, and
200 industrial and other customers. Customer base growth was
approximately 0.5 percent compared to 2006. In addition, the Company
has firm power commitments to nearby municipalities and has contingency reserve
requirements consistent with Reliability First Corp. standards.
The
principal industries served include polycarbonate resin (Lexan®) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For the
year ended December 31, 2007, retail and firm wholesale electricity sales
totaled 6,216.5 GWh, resulting in revenues of approximately $448.1
million. Residential customers accounted for 36 percent of 2007
revenues; commercial 25 percent; industrial 31 percent, and municipal and other
8 percent. In addition, the Company sold 921.3 GWh through
optimization activities in 2007, generating revenue, net of purchased power
costs, of $39.8 million.
System
Load
Total
load for each of the years 2003 through 2007 at the time of the system summer
peak, and the related reserve margin, is presented below in MW.
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Date
of summer peak load
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8/08/2007
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8/10/2006
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7/25/2005
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7/13/2004
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8/27/2003
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Total
load at peak (1)
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1,341 | 1,325 | 1,315 | 1,222 | 1,272 | |||||||||||||||
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Generating
capability
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1,295 | 1,351 | 1,351 | 1,351 | 1,351 | |||||||||||||||
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Firm
purchase supply
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130 | 107 | 107 | 105 | 32 | |||||||||||||||
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Interruptible
contracts
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62 | 62 | 76 | 51 | 95 | |||||||||||||||
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Total
power supply capacity
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1,487 | 1,520 | 1,534 | 1,507 | 1,478 | |||||||||||||||
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Reserve
margin at peak
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11 | % | 15 | % | 17 | % | 23 | % | 16 | % | ||||||||||
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(1)
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The
total load at peak is increased 25 MW in 2007, 2006, 2005, and 2003 from
the total load actually experienced. The additional 25 MW
represents load that would have been incurred if Summer Cycler program had
not been activated. The 25 MW is also included in the
interruptible contract portion of the Company’s total power supply
capacity in those years. On the date of peak in 2004, Summer
Cycler program was not activated.
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The
winter peak load for the 2006-2007 season of approximately 961 MW occurred on
December 7, 2006. The prior year winter peak load was approximately
935 MW, occurring on December 20, 2005.
Generating
Capability
Installed
generating capacity as of December 31, 2007, was rated at 1,295
MW. Coal-fired generating units provide 1,000 MW of capacity, and
natural gas or oil-fired turbines used for peaking or emergency conditions
provide 295 MW. Electric generation for 2007 was fueled by coal (98
percent) and natural gas (2 percent). Oil was used only for testing
of gas/oil-fired peaking units. The Company generated approximately
6,873 GWh in 2007. Further information about the Company’s owned
generation is included in "Item 2 Properties".
In
January 2008, the Company requested authority from the IURC to build a 100 MW
gas-fired turbine peaking unit in Gibson County Indiana. If approved, it
would be operational by 2010. The Company discontinued operations of
Culley Unit 1 (50 MW) effective December 31, 2006.
There are
substantial coal reserves in the southern Indiana area, and coal for coal-fired
generating stations has been supplied from operators of nearby Indiana coal
mines, including those owned by Vectren Fuels, Inc., a wholly owned subsidiary
of Vectren. Approximately 3.3 million tons of coal were purchased for
generating electricity during 2007, of which approximately 92 percent was
supplied by Vectren Fuels, Inc. from its mines and third party
purchases. The average cost of coal consumed in generating electric
energy for the years 2003 through 2007 follows:
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Year
Ended December 31,
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Avg.
Cost Per
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2007
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2006
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2005
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2004
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2003
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|||||||||||||||
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Ton
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$ | 40.23 | $ | 37.51 | $ | 30.27 | $ | 27.06 | $ | 24.91 | ||||||||||
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MWh
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19.78 | 18.44 | 14.94 | 13.06 | 11.93 | |||||||||||||||
Firm
Purchase Supply
The
Company maintains a 1.5 percent interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies,
including SIGECO, and supplies power requirements to the United States
Department of Energy’s (DOE) uranium enrichment plant near Portsmouth,
Ohio. The participating companies are entitled to receive from OVEC,
and are obligated to pay for, any available power in excess of the DOE contract
demand. At the present time, the DOE contract demand is essentially
zero. Because of this decreased demand, the Company’s 1.5 percent
interest in the OVEC makes available approximately 30 MW of capacity for use in
other operations. The Company purchased approximately 231 GWh from
OVEC in 2007.
The
Company has a capacity contract with Duke Energy Marketing America, LLC. (Duke)
to purchase as much as 100 MW at any time from a power plant located in
Vermillion County Indiana. The contract ends on December 31,
2009. The Company purchased approximately 17 GWh under this contract
in 2007.
Other
Power Purchases
The
Company also purchases power as needed principally from the MISO to supplement
its generation and firm purchase supply in periods of peak
demand. Volumes purchased principally from the MISO in 2007 totaled
416 GWh.
Interconnections
The
Company has interconnections with Louisville Gas and Electric Company, Duke
Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier
Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and
the City of Jasper, Indiana, providing the historic ability to simultaneously
interchange approximately 500 MW. However, the ability of the Company
to effectively utilize the electric transmission grid in order to achieve its
desired import/export capability has been, and may continue to be, impacted as a
result of the ongoing changes in the operation of the Midwestern transmission
grid. The Company, as a member of the Midwest Independent System
Operator (MISO), has turned over operational control of the interchange
facilities and its own transmission assets, like many other Midwestern electric
utilities, to MISO. See “Item 7 Management’s Discussion and Analysis
of Results of Operations and Financial Condition” regarding the Company’s
participation in MISO.
Competition
The
utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states have passed legislation allowing
electricity customers to choose their electricity supplier in a competitive
electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such
legislation. Ohio regulation allows gas customers to choose their
commodity supplier. The Company implemented a choice program for its
gas customers in Ohio in January 2003. At December 31, 2007, over
77,000 customers in Vectren’s Ohio service territory purchase natural gas from a
supplier other than the utility. Margin earned for transporting
natural gas to those customers, who have purchased natural gas from another
supplier, are generally the same as those earned by selling gas under Ohio
tariffs. Indiana has not adopted any regulation requiring gas choice;
however, the Company operates under approved tariffs permitting large volume
customers to choose their commodity supplier.
On
February 4, 2008, the Company along with the OCC and other interveners filed a
settlement agreement with the PUCO regarding the first two stages of a
three stage plan to exit the merchant function in the Company’s Ohio service
territory. As designed, the terms and conditions of the plan allow in
stage one for a regulator-approved auction to select qualified wholesale
suppliers that will supply gas commodity to the Company for resale to its
customers at auction-determined standard pricing. In stage two, the
Company will no longer sell natural gas directly to customers; rather a
regulator-approved auction will select state-certified Choice suppliers that
will sell gas commodity to customers at auction-determined standard pricing and
the Company will transport that gas supply to the customers. In the third
stage, which is not part of this application filing, it is contemplated that all
of the Company’s Ohio customers will choose their commodity supplier from
state-certified Choice suppliers in the competitive market. The
settlement agreement includes an Exit Transition Cost rider which, if approved,
will allow the Company to recover costs associated with the transition to this
market structure. As the cost of gas is currently passed through to
customers through a regulator approved recovery mechanism, the impact of exiting
the merchant function should not have a material impact on Company earnings or
financial condition. If the settlement agreement is approved, the
Company’s transition to this market structure will commence in mid to late
2008.
Regulatory and Environmental
Matters
See “Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s regulatory environment and environmental
matters.
Personnel
As of
December 31, 2007, the Company and its consolidated subsidiaries had 1,639
employees, of which 798 are subject to collective bargaining
arrangements.
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.
In
January 2004, the Company reached a five-year labor agreement, ending December
2008, with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America Locals 12213 and 7441.
ITEM
1A. RISK FACTORS
Investors
should consider carefully the following factors that could cause the Company’s
operating results and financial condition to be materially adversely
affected. New risks may emerge at any time, and the Company cannot
predict those risks or estimate the extent to which they may affect the
Company’s businesses or financial performance.
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 repayment of indebtedness
from its subsidiaries 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 the Company, 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.
Utility
Holdings operates in an increasingly competitive industry, which may affect its
future earnings.
The
utility industry has been undergoing dramatic structural change for several
years, resulting in increasing competitive pressure faced by electric and gas
utility companies. Increased competition may create greater risks to
the stability of Vectren’s earnings generally and may in the future reduce its
earnings from retail electric and gas sales. Currently, several
states, including Ohio, have passed legislation that allows customers to choose
their electricity supplier in a competitive market. Indiana has not
enacted such legislation. Ohio regulation also provides for choice of
commodity providers for all gas customers. In 2003, the Company
implemented this choice for its gas customers in Ohio. Indiana has
not adopted any regulation requiring gas choice except for large-volume
customers. 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, prospects, 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.
Vectren’s
gas and electric utility sales are sensitive to variations in weather
conditions. The Company forecasts utility sales on the basis of
normal weather, which represents a 30-year historical average. Since
Vectren does not have a weather-normalization mechanism for its electric
operations or its Ohio natural gas operations, significant variations from
normal weather could have a material impact on its earnings. However,
the impact of weather on the gas operations in the Company’s Indiana territories
has been significantly mitigated through the implementation on October 15, 2005,
of a normal temperature adjustment mechanism.
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,
and coal mining.
Risks
related to the regulation of Utility Holdings’ 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. In particular, Vectren is subject to
regulation by the FERC, the NERC (North American Electric Reliability
Corporation), the IURC and the PUCO. These authorities regulate many
aspects of its transmission and distribution operations, including construction
and maintenance of facilities, operations, and safety. In addition,
these regulatory agencies regulate the rates that Utility Holdings’ 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. 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, a disallowance of gas costs 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 Utility Holdings’ 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.
Further,
there are proposals to address global climate change that would regulate carbon
dioxide (CO2) and other
greenhouse gases and other proposals that would mandate an investment in
renewable energy sources. Any future legislative or regulatory
actions taken to address global climate change or mandate renewable energy
sources could adversely affect Utility Holdings’ business,
prospects, financial condition and results of operations by, for
example, requiring changes in, and increased costs related to, the
Company’s fossil fuel generating plants and increased costs to acquire renewable
energy sources.
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
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 purchased power costs. Such
operational risks can arise from circumstances such as facility shutdowns due to
equipment failure or operator error; interruption of fuel supply or increased
prices of fuel as contracts expire; disruptions in the delivery of electricity;
inability to comply with regulatory or permit requirements; labor disputes; and
natural disasters.
The
impact of MISO participation is uncertain.
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
MISO. The MISO serves the electrical transmission needs of much of the
Midwest and maintains operational control over Vectren’s electric transmission
facilities as well as that of other Midwest utilities.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a pending Day 3 market, where MISO plans to
provide bid-based regulation and contingency operating reserve markets, it is
difficult to predict near term operational impacts. MISO has
indicated that the Day 3 ancillary services market would begin in June
2008.
The need
to expend capital for improvements to the transmission system, both to Utility
Holdings’ facilities as well as to those facilities of adjacent utilities, over
the next several years is expected to be significant. As part of its
recent rate case, SIGECO obtained approval to recover costs for certain
transmission projects through its MISO tracker.
Wholesale
power marketing activities may add volatility to earnings.
Utility
Holdings’ regulated electric utility engages in wholesale power marketing
activities that primarily involve asset optimization
strategies. These optimization strategies primarily involve the
offering of utility-owned or contracted generation into the MISO hourly and real
time markets. As part of these strategies, the Company may also
execute energy contracts that are integrated with portfolio requirements around
power supply and delivery. Margin earned from these activities above
or below $10.5 million is shared evenly with customers. These
earnings from wholesale marketing activities may vary based on fluctuating
prices for electricity and the amount of electric generating capacity or
purchased power available, beyond that needed to meet firm service
requirements.
Catastrophic
events could adversely affect Vectren’s facilities and operations.
Catastrophic
events such as fires, earthquakes, explosions, floods, tornados, terrorist acts
or other similar occurrences could adversely affect Vectren’s facilities,
operations, financial condition and results of operations.
Workforce
risks could affect 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; and that it will be unable
to reach collective bargaining arrangements with the unions that represent
certain of its workers, which could result in work stoppages.
A
downgrade (or negative outlook) in or withdrawal of Utility Holdings’ credit
ratings, or the credit ratings of bond insurers that insure certain long-term
debt of SIGECO, could negatively affect its ability to access capital and its
cost.
The
following table shows the current ratings assigned to certain outstanding debt
by Moody’s and Standard & Poor’s:
|
Current
Rating
|
||
|
Standard
|
||
|
Moody’s
|
&
Poor’s
|
|
|
Utility
Holdings and Indiana Gas senior unsecured debt
|
Baa1
|
A-
|
|
Utility
Holdings commercial paper program
|
P-2
|
A-2
|
|
SIGECO’s
senior secured debt
|
A-3
|
A
|
The
current outlook of both Standard and Poor’s and Moody’s is stable and both
categorize the ratings of the above securities as investment grade. A
security rating is not a recommendation to buy, sell, or hold
securities. The rating is subject to revision or withdrawal at any
time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade
rating is BBB- and Baa3, respectively.
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 its ratings or, in each case, the ratings
of its subsidiaries, it may significantly limit its 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 that the Company will have access to the equity capital markets
to obtain financing when necessary or desirable.
SIGECO
has approximately $103 million of tax-exempt adjustable rate long-term debt
where the interest rates on this debt are reset every seven days through an
auction process. In February 2008, significant disruptions occurred
in the overall auction rate debt markets. As a result, many auctions
of tax-exempt debt, including some of those involving SIGECO's auction rate
debt, failed as a result of insufficient order interest from potential
investors. These failures are largely attributable to a lack of
liquidity in the market place arising from downgrades in, and negative watches
regarding, credit ratings of monoline insurers that guarantee the timely
repayment of bond principal and interest if an issuer defaults, as well as from
disruptions in the overall financial markets. Monoline insurer Ambac
Assurance Corporation insures the Company's auction rate long-term
debt. As a result of these failed auctions, interest rates associated
with these instruments reset to the maximum rates permitted under the various
debt indentures of 10 percent to 15 percent for the following
week. On a weekly basis, interest expense using these maximum rates
is approximately $200,000 higher than the average weekly interest expense based
on rates experienced during 2007.
Subject
to applicable notice provisions, SIGECO may, at its option, redeem this auction
rate debt at par value plus the accrued and unpaid interest or elect to utilize
other interest rate modes available to it as defined in the various debt
indentures. SIGECO provided notice to current holders of this debt
during late February 2008 that such debt will be converted from the auction rate
mode into a daily interest rate mode during March 2008 and will be subject to
mandatory tender for purchase on the conversion date at 100 percent of the
principal amount plus accrued interest. While the Company completes
its conversion from the current auction rate mode to the daily interest rate
mode, it may continue to experience increased interest
costs. Following conversion to the daily mode, expected to be
completed by March 14, SIGECO may again convert the debt to other interest rate
modes and remarket it to investors or redeem the debt and reissue new debt,
including the possibility of replacing the outstanding debt with taxable debt
from Utility Holdings.
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. Material adverse
developments affecting these businesses may result in a downgrade in Utility
Holdings’ credit ratings, 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
58,130 acres of land with an estimated ready delivery from storage capability of
5.6 BCF of gas with maximum peak day delivery capabilities of 145,000 MCF per
day. Indiana Gas also owns and operates three liquefied petroleum
(propane) air-gas manufacturing plants located in Indiana with the ability to
store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of
manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted for 17.9 BCF of storage
with a maximum peak day delivery capability of 298,579 MMBTU per
day. Indiana Gas’ gas delivery system includes 12,699 miles of
distribution and transmission mains, all of which are in Indiana except for
pipeline facilities extending from points in northern Kentucky to points in
southern Indiana so that gas may be transported to Indiana and sold or
transported by Indiana Gas to ultimate customers in Indiana.
SIGECO
owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
108,500 MCF per day. In addition to its company owned storage
delivery capabilities, SIGECO has contracted for 0.5 BCF of storage with a
maximum peak day delivery capability of 19,166 MMBTU per
day. SIGECO's gas delivery system includes 3,192 miles of
distribution and transmission mains, all of which are located in
Indiana.
The Ohio
operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants, all of which are located in Ohio. The plants
can store 0.5 million gallons of propane, and the plants can manufacture for
delivery 52,187 MCF of manufactured gas per day. In addition to its
propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF
of storage with a maximum peak day delivery capability of 246,080 MMBTU per
day. The Ohio operations’ gas delivery system includes 5,468 miles of
distribution and transmission mains, all of which are located in
Ohio.
Electric Utility
Services
SIGECO's
installed generating capacity as of December 31, 2007, was rated at 1,295
MW. SIGECO's coal-fired generating facilities are the Brown Station
with two units of 490 MW of combined capacity, located in Posey County
approximately eight miles east of Mt. Vernon, Indiana; the Culley Station
with two units of
360 MW of combined capacity, and Warrick Unit 4 with 150 MW of
capacity. Both the Culley and Warrick Stations are located in Warrick
County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4)
located at the Brown Station; two Broadway Avenue Gas Turbines located in
Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1,
50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located
northeast of Evansville in Vanderburgh County, Indiana with a combined capacity
of 20 MW. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are
also equipped to burn oil. Total capacity of SIGECO's six gas
turbines is 295 MW, and they are generally used only for reserve, peaking, or
emergency purposes due to the higher per unit cost of generation.
SIGECO's
transmission system consists of 926 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 31 substations with an
installed capacity of 5,457 megavolt amperes (Mva). The electric
distribution system includes 4,211 pole miles of lower voltage overhead lines
and 340 trench miles of conduit containing 1,878 miles of underground
distribution cable. The distribution system also includes 98
distribution substations with an installed capacity of 3,002 Mva and 53,456
distribution transformers with an installed capacity of 2,497 Mva.
SIGECO
owns utility property outside of Indiana approximating nine miles of 138,000
volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Property Serving as
Collateral
SIGECO's
properties are subject to the lien of the First Mortgage Indenture dated as of
April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and
Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM
3. LEGAL PROCEEDINGS
The
Company is party to various legal proceedings arising in the normal course of
business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position, results of operations, or cash
flows. See the notes to the consolidated financial statements
regarding commitments and contingencies, environmental matters, rate and
regulatory matters. The consolidated financial statements are
included in “Item 8 Financial Statements and Supplementary Data.”
ITEM
4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
No
matters were submitted during the fourth quarter to a vote of security
holders.
PART
II
|
|
ITEM
5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS, AND ISSUER PURCHASES OF EQUITY
SECURITIES
|
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
2007, Utility Holdings paid dividends to its parent company of $19.1 million in
each quarter.
During
2006, Utility Holdings paid dividends to its parent company of $18.7 million in
each of the first, second and third quarters, and $19.4 million in the fourth
quarter.
On
January 30, 2008, the board of directors declared a $20.8 million dividend,
payable to Vectren on February 29, 2008.
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)
|
2007
|
2006
|
2005
|
2004
|
2003
|
|||||||||||||||
|
Operating
Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 1,759.0 | $ | 1,656.5 | $ | 1,781.8 | $ | 1,498.0 | $ | 1,448.8 | ||||||||||
|
Operating
income
|
244.4 | 209.0 | 216.6 | 196.3 | 197.2 | |||||||||||||||
|
Income
before cumulative effect of change
|
||||||||||||||||||||
|
in
accounting principle
|
106.5 | 91.4 | 95.1 | 83.1 | 85.6 | |||||||||||||||
|
Net
income
|
106.5 | 91.4 | 95.1 | 83.1 | 85.6 | |||||||||||||||
|
Balance
Sheet Data:
|
||||||||||||||||||||
|
Total
assets
|
$ | 3,643.7 | $ | 3,440.8 | $ | 3,391.2 | $ | 3,147.7 | $ | 2,925.1 | ||||||||||
|
Redeemable
preferred stock
|
- | - | - | 0.1 | 0.2 | |||||||||||||||
|
Long-term
debt - net of current maturities
|
||||||||||||||||||||
|
&
debt subject to tender
|
1,062.6 | 1,025.3 | 997.8 | 941.3 | 960.5 | |||||||||||||||
|
Common
shareholder's equity
|
1,090.4 | 1,056.7 | 1,023.8 | 985.4 | 979.8 | |||||||||||||||
|
|
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 Holding’s 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
In 2007,
the Utility Holdings’ earnings were $106.5 million compared to $91.4 million in
2006 and $95.1 million in 2005. The increase in 2007 compared to 2006
resulted from base rate increases in the Vectren South service territory, the
combined impact of residential and commercial usage and lost margin recovery,
favorable weather, and increased wholesale power marketing
margins. The increase was offset somewhat by increased operating
costs including depreciation expense and a lower effective tax rate in
2006.
In 2006
compared to 2005, the decline in Utility Holdings’ earnings is primarily the
result of lower wholesale power marketing margins as well as declines in
customer usage, higher depreciation and interest costs. The decline
was mitigated somewhat by the implementation of regulatory initiatives noted
above, the impact of a lower effective tax rate, and a gain realized on the sale
of a storage asset.
In the
Company’s electric and Ohio natural gas service territories which are not
protected by weather normalization mechanisms, management estimates the 2007
margin impact of weather experienced to be $5.5 million favorable compared to
30-year normal temperatures. In 2006 and 2005 weather across all
utilities was unfavorable compared to 30-year normal
temperatures. Management estimates the effect of weather compared to
normal was unfavorable $4 million after tax in 2006 and unfavorable $3 million
after tax in 2005. The 2007 and 2006 weather effect is net of normal
temperature adjustment (NTA) mechanism impacts. The NTA was
implemented in the Company’s Indiana natural gas service territories in the
fourth quarter of 2005.
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
Cost of gas
sold. Electric Utility margin is calculated as Electric Utility revenues
less Cost of fuel &
purchased power. These measures exclude Other operating expenses,
Depreciation and amortization, and Taxes other than income
taxes, which are included in the calculation of operating
income. The Company believes Gas Utility and Electric Utility margins
are better indicators of relative contribution than revenues since gas prices
and fuel costs can be volatile and are generally collected on a
dollar-for-dollar basis from customers.
Sales of
natural gas and electricity to residential and commercial customers are seasonal
and are impacted by weather. Trends in average use among natural gas
residential and commercial customers have tended to decline in recent years as
more efficient appliances and furnaces are installed and the price of natural
gas has increased. Normal temperature adjustment (NTA) and lost margin
recovery mechanisms largely mitigate the effect on Gas Utility margin that would
otherwise be caused by variations in volumes sold due to weather and changing
consumption patterns. Indiana Gas’ territory has both an NTA since 2005
and lost margin recovery since December 2006. SIGECO’s natural gas
territory has an NTA since 2005, and lost margin recovery began when new base
rates went into effect August 1, 2007. The Ohio service territory has lost
margin recovery since October 2006, but does not have an NTA mechanism.
SIGECO’s electric service territory does not have an NTA mechanism but has
recovery of past demand side management costs.
Gas and
electric margin generated from sales to large customers (generally industrial
and other contract customers) is primarily impacted by overall economic
conditions. Margin is also impacted by the collection of state mandated
taxes, which fluctuate with gas and fuel costs, as well as other tracked
expenses. Expenses subject to tracking mechanisms include Ohio bad
debts and percent of income payment plan expenses, Indiana gas pipeline
integrity management costs, and costs to fund Indiana energy efficiency
programs. Certain operating costs associated with operating
environmental compliance equipment were also tracked prior to their recovery in
base rates that went into effect on August 15, 2007. The August
SIGECO rate orders also provide for the tracking of MISO revenues and costs, as
well as the gas cost component of bad debt expense and unaccounted for
gas. Electric generating asset optimization activities are primarily
affected by market conditions, the level of excess generating capacity, and
electric transmission availability. Following is a discussion and analysis
of margin generated from regulated utility operations.
Gas
Utility margin (Gas Utility revenues less Cost of gas sold)
Gas
Utility margin and throughput by customer type follows:
|
Year
Ended December 31,
|
|||||
|
(In
millions)
|
2007
|
2006
|
2005
|
||
|
Gas
utility revenues
|
$ 1,269.4
|
$ 1,232.5
|
$ 1,359.7
|
||
|
Cost
of gas sold
|
847.2
|
841.5
|
973.3
|
||
|
Total
gas utility margin
|
$ 422.2
|
$ 391.0
|
$ 386.4
|
||
|
Margin
attributed to:
|
|||||
|
Residential
& commercial customers
|
$ 357.1
|
$ 330.2
|
$ 333.2
|
||
|
Industrial
customers
|
48.3
|
48.0
|
48.3
|
||
|
Other
customers
|
16.8
|
12.8
|
4.9
|
||
|
Sold
& transported volumes in MMDth attributed to:
|
|||||
|
Residential
& commercial customers
|
108.4
|
97.7
|
112.9
|
||
|
Industrial
customers
|
86.2
|
84.9
|
87.2
|
||
|
Total
sold & transported volumes
|
194.6
|
182.6
|
200.1
|
||
Gas
Utility margins were $422.2 million for the year ended December 31, 2007, an
increase of $31.2 million compared to 2006. Residential and
commercial customer usage, including lost margin recovery, increased margin
$13.3 million year over year. For all of 2007, Ohio weather was 6
percent warmer than normal, but approximately 6 percent colder than the prior
year and resulted in an estimated increase in margin of approximately $2.0
million compared to 2006. Margin increases associated with the
Vectren South base rate increase, effective August 1, 2007, were $3.3
million. Recovery of gas storage carrying costs in Ohio was $2.3
million. Lastly, operating costs, including revenue and usage taxes
recovered dollar-for-dollar in margin, increased gas margin $10.3 million year
over year. During 2007, the company resolved all remaining issues
related to a 2005 disallowance by the PUCO of gas costs incurred by the Ohio
utility operations, resulting in an additional charge of $1.1
million. The average cost per dekatherm of gas purchased for the year
ended December 31, 2007, was $8.14 compared to $8.64 in 2006 and $9.05 in
2005.
Gas
Utility margins were $391.0 million for the year ended December 31, 2006, an
increase of $4.6 million compared to 2005. A full year of base rate
increases implemented in the Company’s Ohio service territory which increased
margin $4.2 million, a $4.1 million disallowance of Ohio gas costs in 2005, the
effects of the NTA implemented in 2005 in the Company’s Indiana service
territories, and the lost margin recovery authorizations implemented in the
fourth quarter of 2006, more than offset the effects of warm weather, lower
usage, and decreased tracked expenses recovered dollar for dollar in
margin.
For the
year ended December 31, 2006, compared to 2005, management estimates that
weather 14 percent warmer than normal and 9 percent warmer than prior year would
have decreased margins $13.1 million compared to the prior year, had the NTA not
been in effect. Weather, net of the NTA, resulted in an approximate
$2.0 million year over year increase in Gas Utility
margin. Incremental revenue associated with the lost margin
recovery totaled $2.0 million in 2006. Further, for the year ended
December 31, 2006, margin associated with tracked expenses and revenue taxes
decreased $3.4 million.
Electric
Utility Margin (Electric Utility revenues less Cost of fuel and purchased
power)
Electric
Utility margin and volumes sold by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Electric
utility revenues
|
$ | 487.9 | $ | 422.2 | $ | 421.4 | ||||||
|
Cost
of fuel & purchased power
|
174.8 | 151.5 | 144.1 | |||||||||
|
Total
electric utility margin
|
$ | 313.1 | $ | 270.7 | $ | 277.3 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 194.7 | $ | 162.9 | $ | 170.8 | ||||||
|
Industrial
customers
|
75.0 | 70.2 | 66.9 | |||||||||
|
Municipal
& other customers
|
21.8 | 24.0 | 19.8 | |||||||||
|
Subtotal:
Retail & firm wholesale
|
$ | 291.5 | $ | 257.1 | $ | 257.5 | ||||||
|
Asset
optimization
|
$ | 21.6 | $ | 13.6 | $ | 19.8 | ||||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
3,042.9 | 2,789.7 | 2,933.2 | |||||||||
|
Industrial
customers
|
2,538.5 | 2,570.4 | 2,575.9 | |||||||||
|
Municipal
& other customers
|
635.1 | 644.4 | 689.9 | |||||||||
|
Total
retail & firm wholesale volumes sold
|
6,216.5 | 6,004.5 | 6,199.0 | |||||||||
Retail & Firm Wholesale Margin
Electric
retail and firm wholesale utility margins was $291.5 million for the year ended
December 31, 2007. This represents an increase over the prior year of
$34.4 million. Management estimates the year over year increases in
usage by residential and commercial customers due to weather to be $11.8
million. The base rate increase that went into effect on August 15,
2007, produced incremental margin of $17.9 million. During 2007,
cooling degree days were 33 percent above normal compared to 5 percent below
normal in 2005. Recovery of pollution control investments and
expenses increased margin $5.5 million year over year.
Electric
retail and firm wholesale utility margin was $257.1 million for the year ended
December 31, 2006 and was generally flat compared to 2005. The
recovery of pollution control related investments and associated operating
expenses and related depreciation increased margins $2.6 million year over
year. Higher demand charges and other items increased industrial
customer margin approximately $3.2 million year over year. These
increases were offset by decreased residential and commercial
usage. The decreased usage was due primarily to mild weather during
the peak cooling season. For 2006 compared to 2005, the estimated
decrease in margin due to unfavorable weather was $4.6 million ($4.0 million for
below normal cooling weather and $0.6 million for below normal heating
weather). In 2005, cooling degree days were 9 percent above
normal.
Margin
from Asset Optimization Activities
Periodically,
generation capacity is in excess of that needed to serve native load and firm
wholesale customers. The Company markets and sells this unutilized
generating and transmission capacity to optimize the return on its owned
assets. A majority of the margin generated from these activities is
associated with wholesale off-system sales, and substantially all off-system
sales occur into the MISO Day Ahead market.
Asset
optimization activity is comprised of the following:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Off-system
sales
|
$ | 16.9 | $ | 14.2 | $ | 15.3 | ||||||
|
Transmission
system sales
|
4.7 | 3.5 | 4.5 | |||||||||
|
Other
|
- | (4.1 | ) | - | ||||||||
|
Total
asset optimization
|
$ | 21.6 | $ | 13.6 | $ | 19.8 | ||||||
For the year ended December 31, 2007, net asset optimization margins were $21.6 million, which represents an increase of $8.0 million, compared to 2006. The increase is primarily due to losses on financial contracts experienced in 2006 and higher fourth quarter wholesale prices. Margins in 2006 decreased $6.2 million when compared to 2005 primarily due to the financial contract losses experienced in 2006 and lower volumes sold off system. In 2006, the availability of excess capacity was reduced by scheduled outages associated with the installation of environmental compliance equipment. Off-system sales totaled 948.9 GWh in 2007, compared to 889.4 GWh in 2006 and 1,208.1 GWh in 2005.
Operating
Expenses
Other
Operating
For the
year ended December 31, 2007, Other operating expenses were
$266.1 million, which represents an increase of $27.1 million, compared to
2006. Operating costs recovered dollar for dollar in margin,
including costs funding new Indiana energy efficiency programs, increased $9.5
million year over year. Increases in operating costs associated with
lost margin recovery and conservation initiatives that are not directly
recovered in margin were $1.3 million year over year. Costs directly
attributable to the Vectren South rate cases, including amortization of prior
deferred costs, totaled $3.6 million in 2007. Expenses in 2006 are
offset by the gain on the sale of a storage asset of approximately $4.4
million. The remaining increases are primarily due to increased wage
and benefit costs.
The 2006
$4.4 million gain on sale of a storage asset, partially offset by higher
electric generation chemical costs and bad debt expense in the Company’s Indiana
service territories were the primary factors decreasing operating expense in
2006 compared to 2005.
Depreciation
& Amortization
Depreciation
expense increased $7.1 million in 2007 compared to 2006 and $10.0 million in
2006 compared to 2005. The increases were primarily due to increased
utility plant in service. Expense in 2007 also includes $1.8 million
of amortization associated with prior electric demand side management costs
pursuant to the August 15,
2007, electric base rate order.
Taxes
Other Than Income Taxes
Taxes
other than income taxes increased $3.9 million in 2007 compared to 2006 and
decreased $1.0 million in 2006 compared 2005. The fluctuations are
primarily attributable to variations in utility receipts, excise, and usage
taxes. These variations resulted primarily from volatility in
revenues and gas volumes sold. In 2007 and 2006, property taxes also
increased due to increased plant in service.
Other
Income-Net
Other-net reflects income of
$9.4 million in 2007 compared to $7.6 million in 2006 and $5.9 million in
2005. The increases relate primarily to the capitalization of funds
used during construction due to increased capital spending and higher interest
income.
Interest
Expense
In 2007,
interest expense increased $3.1 million compared to 2006 and increased $7.6
million in 2006 compared to 2005. The increases are primarily driven
by rising interest rates during the period and are also impacted by higher
levels of short-term borrowings.
The 2007
increase was mitigated somewhat by the full impact of financing transactions
completed in October 2006 in which approximately $93 million in debt related
proceeds were raised and used to retire debt with a higher interest
rate. Interest costs in 2006 reflect permanent financing transactions
completed in the fourth quarter of 2005 in which $150 million in debt-related
proceeds were received and used to retire short-term borrowings and other
long-term debt.
Income
Taxes
Federal
and state income taxes
increased $19.0 million in 2007 compared to 2006 and decreased $9.8 million in
2006 compared to 2005. The changes are impacted primarily by
fluctuations in pre-tax income and a lower effective tax rate in
2006.
The lower
effective tax rate in 2006 primarily relates to a $3.1 million favorable impact
for an Indiana tax law change that resulted in the recalculation of certain
state deferred income tax liabilities. Income taxes in 2006 also
include other adjustments, including adjustments to reflect income taxes
reported on 2005 state and federal income tax returns. Income taxes
recorded in 2005 reflect favorable adjustments to accruals resulting from the
conclusion of state tax audits and other adjustments.
Environmental
Matters
The
Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water
quality. Pursuant to environmental regulations, the Company is
required to obtain operating permits for the electric generating plants that it
owns or operates and construction permits for any new plants it might propose to
build. Regulations concerning air quality establish standards with
respect to both ambient air quality and emissions from electric generating
facilities, including particulate matter, sulfur dioxide (SO2), nitrogen
oxide (NOx), and mercury. Regulations concerning water quality
establish standards relating to intake and discharge of water from electric
generating facilities, including water used for cooling purposes in electric
generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations.
Clean Air/Climate
Change
In March
of 2005 USEPA finalized two new air emission reduction regulations. The
Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring
further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2) emissions
from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an
allowance cap and trade program requiring further reductions in mercury
emissions from coal-burning power plants. Both sets of regulations require
emission reductions in two phases. The first phase deadline for both rules
is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance
with the emission reductions required under CAIR is 2015, while the second phase
deadline for compliance with the emission reduction requirements of CAMR is
2018. However, on February 8, 2008, the US Court of Appeals for the
District of Columbia vacated the federal CAMR regulations. At this
time it is uncertain how this decision will affect Indiana’s recently finalized
CAMR implementation program.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990 and to further
comply with CAIR and CAMR of 2005, SIGECO has received authority from the IURC
to invest in clean coal technology. Using this authorization, SIGECO
invested approximately $258 million in Selective Catalytic Reduction (SCR)
systems at its coal fired generating stations. SCR technology is the most
effective method of reducing NOx emissions where high removal efficiencies are
required. To further reduce particulate matter emissions, the Company
invested approximately $49 million in a fabric filter at its largest generating
unit (287 MW). These investments were included in rate base for purposes
of determining new base rates that went into effect on August 15, 2007, (See
Rate and Regulatory Matter Section). Prior to being included in base
rates, return on investments made and recovery of related operating expenses
were recovered through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order, as updated with an increased spending level, allows SIGECO to recover an
approximate 8 percent return on up to $92 million, excluding
AFUDC, in capital investments through a rider mechanism which is
updated every six months for actual costs incurred. The Company may file
periodic updates with the IURC requesting modification to the spending
authority. As of December 31, 2007, the Company has invested approximately
$53 million in this project. The Company expects the SO2 scrubber
will be operational in 2009. At that time, operating expenses including
depreciation expense associated with the scrubber will also be recovered through
a rider mechanism.
Once the
SO2
scrubber is operational, SIGECO’s coal fired generating fleet will be 100
percent scrubbed for SO2, 90
percent controlled for NOx. The use of SCR technology positions the
Company to be in compliance with the CAIR deadlines specifying reductions in NOx
emissions by 2009 and further reductions by 2015. Not only does SIGECO's
investments in scrubber, SCR and fabric filter technology position it to comply
with reductions described in the original 2005 mercury emission regulations and
Indiana’s current CAMR implementation plans, it will also likely comply with
more stringent mercury reductions that might follow from revised
regulations.
If
legislation requiring reductions in carbon dioxide and other greenhouse gases or
mandating energy from renewable sources is adopted, such regulation could
substantially affect both the costs and operating characteristics of the
Company’s fossil fuel generating plants and nonutility coal mining
operations. At this time and in the absence of final legislation,
compliance costs and other effects associated with reductions in greenhouse gas
emissions or obtaining renewable energy sources remain
uncertain.
SIGECO is
studying renewable energy alternatives, and on April 9, 2007, filed a green
power rider in order to allow customers to purchase green power and to obtain
approval of a contract to purchase 30 MW of power generated by wind
energy. The wind contract has been approved. Future
filings with the IURC with regard to new generation and/or further environmental
compliance plans will include evaluation of potential carbon
requirements.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that operated
these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded costs that it
reasonably expects to incur totaling approximately $21 million.
The
estimated accrued costs are limited to Indiana Gas’ share of the remediation
efforts. Indiana Gas has arrangements in place for 19 of the 26 sites
with other potentially responsible parties (PRP), which serve to limit Indiana
Gas’ share of response costs at these 19 sites to between 20 percent and 50
percent. With respect to insurance coverage, Indiana Gas has received
and recorded settlements from all known insurance carriers under insurance
policies in effect when these plants were in operation in an aggregate amount
approximating $20 million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has filed a declaratory judgment action against its insurance carriers seeking a
judgment finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit. While the total costs that may be incurred in connection
with addressing these sites cannot be determined at this time, SIGECO has
recorded costs that it reasonably expects to incur totaling approximately $8
million. With respect to insurance coverage, SIGECO has received and
recorded settlements from insurance carriers under insurance policies in effect
when these sites were in operation in an aggregate amount approximating the
costs it expects to incur.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had no material impact on results of operations or
financial condition since costs recorded to date approximate PRP and insurance
settlement recoveries. While the Company’s utilities have recorded
all costs which they presently expect to incur in connection with activities at
these sites, it is possible that future events may require some level of
additional remedial activities which are not presently foreseen and those costs
may not be subject to PRP or insurance recovery.
Jacobsville Superfund
Site
On July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The
USEPA has identified four sources of historic lead
contamination. These four sources shut down manufacturing operations
years ago. When drawing up the boundaries for the listing, the USEPA
included a 250 acre block of properties surrounding the Jacobsville
neighborhood, including Vectren's Wagner Operations Center. Vectren's
property has not been named as a source of the lead contamination, nor does the
USEPA's soil testing to date indicate that the Vectren property contains lead
contaminated soils. Vectren's own soil testing, completed during the
construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils. At this time, Vectren
anticipates only additional soil testing could be requested by the USEPA at some
future date.
Rate
and Regulatory Matters
Gas and
electric operations with regard to retail rates and charges, terms of service,
accounting matters, issuance of securities, and certain other operational
matters specific to its Indiana customers are regulated by the
IURC. The retail gas operations of the Ohio operations are subject to
regulation by the PUCO.
Gas rates
in Indiana contain a gas cost adjustment (GCA) clause, and rates in Ohio contain
a gas cost recovery (GCR) clause. GCA and GCR clauses allow the
Company to charge for changes in the cost of purchased gas. Electric
rates contain a fuel adjustment clause (FAC) that allows for adjustment in
charges for electric energy to reflect changes in the cost of
fuel. The net energy cost of purchased power, subject to an agreed
upon benchmark, is also recovered through regulatory proceedings. The
current benchmark expires in March 2008. A settlement agreement
between the Company and the OUCC to modify and extend the benchmark is awaiting
IURC action. An order is expected during the first quarter of
2008.
GCA, GCR,
and FAC procedures involve periodic filings and IURC and PUCO hearings to
establish the amount of price adjustments for a designated future
period. The procedures also provide for inclusion in later periods of
any variances between the estimated cost of gas, cost of fuel, and net energy
cost of purchased power and actual costs incurred. The Company
records any under-or-over-recovery resulting from gas and fuel adjustment
clauses each month in margin. A corresponding asset or liability is
recorded until the under-or-over-recovery is billed or refunded to utility
customers.
The IURC
has also applied the statute authorizing GCA and FAC procedures to reduce rates
when necessary to limit net operating income to a level authorized in its last
general rate order through the application of an earnings test. The
Company has not surpassed the limits of the earnings test in the recent
past.
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
its Vectren North gas rate case. The order provided for a base rate
increase of $16.3 million and an ROE of 10.2 percent, with an overall rate of
return of 7.8 percent on rate base of approximately $793 million. The
settlement also provides for the recovery of $10.6 million of costs through
separate cost recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $20 million
and the treatment cannot extend beyond four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity
expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved its Vectren
South electric rate case. The settlement agreement provides for an
approximate $60.8 million electric rate increase to cover the Company’s cost of
system growth, maintenance, safety and reliability. The settlement
provides for, among other things: recovery of ongoing costs and deferred costs
associated with the MISO; operations and maintenance (O&M) expense increases
related to managing the aging workforce, including the development of expanded
apprenticeship programs and the creation of defined training programs to ensure
proper knowledge transfer, safety and system stability; increased O&M
expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by Vectren’s sharing equally with
customers any profit earned above or below $10.5 million of wholesale power
margin; recovery of and return on the investment in past demand side management
programs to help encourage conservation during peak load periods; timely
recovery of the Company’s investment in certain new electric transmission
projects that benefit the MISO infrastructure; an overall rate of return of 7.32
percent on rate base of approximately $1,044 million and an allowed return on
equity (ROE) of 10.4 percent. The increase in Electric Utility margin as a
result of this order totaled $17.9 million in 2007.
Vectren South (SIGECO) Gas
Base Rate Order Received
On August
1, 2007, the Company received an order from the IURC which approved its Vectren
South gas rate case. The order provided for a base rate increase of $5.1
million and an ROE of 10.15 percent, with an overall rate of return of 7.20
percent on rate base of approximately $122 million. The settlement
also provides for the recovery of $2.6 million of costs through separate cost
recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $3 million
and the treatment cannot extend beyond three years on each project.
With this
order, the company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity expense.
The increase in Gas Utility
margin as a result of this order totaled $3.3 million in
2007.
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Case Filing
In
November 2007, the Company filed with the PUCO a request for an increase in its
base rates and charges for VEDO’s distribution business in its 17-county service
area in west central Ohio. The filing indicates that an increase in
base rates of approximately $27 million is necessary to cover the ongoing cost
of operating, maintaining and expanding the approximately 5,200-mile
distribution system used to serve 318,000 customers.
In
addition, the Company is seeking to increase the level of the monthly service
charge as well as extending the lost margin recovery mechanism currently in
place to be able to encourage customer conservation and is also seeking approval
of expanded conservation-oriented programs, such as rebate offerings on
high-efficiency natural gas appliances for existing and new home construction,
to help customers lower their natural gas bills. The Company is also
seeking approval of a multi-year bare steel and cast iron capital replacement
program.
The
Company anticipates an order from the PUCO in late 2008.
Ohio and Indiana Lost Margin
Recovery/Conservation Filings
In 2005,
the Company filed conservation programs and conservation adjustment trackers in
Indiana and Ohio designed to help customers conserve energy and reduce their
annual gas bills. The proposed programs would allow the Company to
recover costs of promoting the conservation of natural gas through conservation
trackers that work in tandem with a lost margin recovery
mechanism. These mechanisms are designed to allow the Company to
recover the distribution portion of its rates from residential and commercial
customers based on the level of customer revenues established in each utility’s
last general rate case.
Indiana
In
December 2006, the IURC approved a settlement agreement that provides for a
five-year energy efficiency program. It allows the Company’s Indiana
utilities to recover a majority of the costs of promoting the conservation of
natural gas through conservation trackers that work in tandem with a lost margin
recovery mechanism. The order was implemented in the North service
territory in December 2006, and provides for recovery of 85 percent of the
difference between weather normalized revenues actually collected by the Company
and the revenues approved in the Company’s most recent rate
case. Energy efficiency programs began in the North gas territory in
December 2006. A similar approach regarding lost margin recovery
commenced in the South gas territory on August 1, 2007, as the new base rates
went into effect, allowing for recovery of 100 percent of the difference between
weather normalized revenues collected and the revenues approved in that rate
case. The recent Vectren North base rate order also allows for full
recovery of the difference between weather normalized revenues collected by the
Company and the revenues provided for in that settlement, superseding the
original December 2006 order. While most expenses associated with
these programs are recoverable, in the first program year the Company incurred
$0.9 million in program costs without recovery, of which $0.8 million was
expensed in 2007 and, in addition contributed $0.2 million in assets that are
being depreciated over the term of the program without recovery.
Ohio
In June
2007, the Public Utilities Commission of Ohio (PUCO) approved a settlement that
provides for the implementation of a lost margin recovery mechanism and a
related conservation program for the Company’s Ohio operations. This
order confirms the guidance the PUCO previously provided in a September 2006
decision. The conservation program, as outlined in the September 2006
PUCO order and as affirmed in this order, provides for a two year, $2 million
total conservation program to be paid by the Company, as well as a sales
reconciliation rider intended to be a recovery mechanism for the difference
between the weather normalized revenues actually collected by the Company and
the revenues approved by the PUCO in the Company’s most recent rate
case. Approximately 60 percent of the Company’s Ohio customers are
eligible for the conservation programs. The Ohio Consumer Counselor
(OCC) and another intervener requested a rehearing of the June 2007 order and
the PUCO granted that request in order to have additional time to consider the
merits of the request. In accordance with accounting authorization
previously provided by the PUCO, the Company began recognizing the impact of the
September 2006 order on October 1, 2006, and has recognized cumulative revenues
of $4.6 million, of which $3.3 million was recorded in 2007. The OCC
appealed the PUCO’s accounting authorization to the Ohio Supreme Court, but that
appeal has been dismissed as premature pending the PUCO’s consideration of
issues raised in the OCC’s request for rehearing. Since October 1,
2006, the Company has been ratably accruing its $2 million
commitment.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission
needs of much of the Midwest and maintains operational control over the
Company’s electric transmission facilities as well as that of other Midwest
utilities.
On April
1, 2005, the MISO energy market commenced operation (the Day 2 energy
market). As a result of being a market participant, the Company now bids
its owned generation into the Day Ahead and Real Time markets and procures power
for its retail customers at Locational Marginal Pricing (LMP) as determined by
the MISO market. The Company is typically in a net sales position with
MISO and is only occasionally in a net purchase position. Net positions
are determined on an hourly basis. When the Company is a net seller such
net revenues are included in Electric Utility revenues and
when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased
power. The Company also receives transmission revenue that
results from other members’ use of the Company’s transmission
system. These revenues are also included in Electric Utility
revenues.
Pursuant
to an order from the IURC received in December 2001, certain MISO startup costs
(referred to as Day 1 costs) were deferred, and those deferred costs are now
being recovered through base rates that went into effect on August 15,
2007. On June 1, 2005, Vectren, together with three other Indiana
electric utilities, received regulatory authority from the IURC to recover fuel
related costs and to defer other costs associated with the Day 2 energy
market. The order allows fuel related costs to be passed through to
customers in Vectren’s existing fuel cost recovery proceedings. During
2006, the IURC reaffirmed the definition of certain costs as fuel related; the
Company is following those guidelines. Other MISO fuel related and
non-fuel related administrative costs were deferred, and those deferred costs
are now being recovered through base rates that went into effect on August 15,
2007. The IURC order authorizing new base rates also provides for a
tracking mechanism associated with ongoing MISO-related costs and transmission
revenues.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a pending Day 3 market, where MISO plans to
provide bid-based regulation and contingency operating reserve markets, it is
difficult to predict near term operational impacts. MISO has
indicated that the Day 3 ancillary services market would begin in June
2008.
The need
to expend capital for improvements to the transmission system, both to SIGECO’s
facilities as well as to those facilities of adjacent utilities, over the next
several years is expected to be significant. The Company will timely
recover its investment in certain new electric transmission projects that
benefit the MISO infrastructure at a FERC approved rate of
return.
Weather
Normalization
On
October 5, 2005, the IURC approved the establishment of a normal temperature
adjustment (NTA) mechanism for Vectren Energy Delivery of
Indiana. The OUCC had previously entered into a settlement agreement
with Vectren Energy Delivery of Indiana providing for the NTA. The
NTA affects the Company’s Indiana regulated residential and commercial natural
gas customers and should mitigate weather risk in those customer classes during
the October to April heating season. These Indiana customer classes
represent approximately 60-65 percent of the Company’s total natural gas heating
load.
The NTA
mechanism will mitigate volatility in distribution charges created by
fluctuations in weather by lowering customer bills when weather is colder than
normal and increasing customer bills when weather is warmer than
normal. The NTA has been applied to meters read and bills rendered
after October 15, 2005. Each subsequent monthly bill for the
seven-month heating season is adjusted using the NTA. Revenues
attributable to this order were $4.5 million in 2007 and $13.6 million in 2006
while a downward adjustment to revenues of $1.6 million resulted in
2005.
The order
provides that the Company will make, on a monthly basis, a commitment of
$125,000 to a universal service fund program or other low-income assistance
program for the duration of the NTA or until a general rate
case. SIGECO’s portion of its commitment ceased in August 2007, and
Indiana Gas’ portion of the commitment ceased on February 14, 2008.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
VEDO Base Rate Increase in
2005
On April
13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas
distribution business. The base rate change was implemented on April
14, 2005 and provide for the recovery of some level of on-going costs to comply
with the Pipeline Safety Improvement Act of 2002.
Gas Cost Recovery (GCR)
Audit Proceedings
In 2005,
the PUCO issued an order disallowing the recovery of approximately $9.6 million
of gas costs relating to the two-year audit period ended October 2002 and in
2006, an additional $0.8 million was disallowed related to the audit period
ending October 2005. The initial audit period provided the PUCO staff its
initial review of the portfolio administration arrangement between VEDO and
ProLiance. Since November 1, 2005, the Company has used a provider other
than ProLiance for these services.
Through a
series of rehearings and appeals, including action by the Ohio Supreme Court in
the first quarter of 2007, the Company was required to refund $8.6 million to
customers. In total, the Company has reflected $6.2 million in Cost of gas sold related to
this matter, of which $1.1 million, $4.1 million and $1.0 million were recorded
in 2007, 2005, and 2003, respectively. The impact of the disallowance
includes a sharing of the ordered refund by Vectren’s partner in
ProLiance. As of December 31, 2007, all amounts have been refunded to
customers.
Impact of Recently Issued
Accounting Guidance
FIN
48
On
January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48)
“Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109,
Accounting for Income Taxes. FIN 48 prescribes a recognition
threshold and measurement attribute for financial statement recognition and
measurement of tax positions taken or expected to be taken in an income tax
return. FIN 48 also provides guidance related to reversal of tax
positions, balance sheet classification, interest and penalties, interim period
accounting, disclosure and transition.
At
adoption, the total amount of gross unrecognized tax benefits for uncertain tax
positions, including positions impacting only the timing of tax benefits was
$7.0 million. The accumulation of this amount resulted in an adjustment to
beginning Retained earnings
of $0.9 million.
SFAS
No. 157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
157). SFAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles (GAAP), and
expands disclosures about fair value measurements. This statement
does not require any new fair value measurements; however, the standard will
impact how other fair value based GAAP is applied. SFAS 157 is
effective for financial statements issued for fiscal years beginning after
November 15, 2007. However, in December 2007, the FASB issued
proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). This proposed FSP partially defers the
effective date of Statement 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of this FSP. The Company will adopt SFAS 157 on January 1, 2008,
except as it applies to those nonfinancial assets and nonfinancial liabilities
as noted in proposed FSP FAS 157-b. The partial adoption of SFAS 157
will not have a material impact on our financial position, results of operations
or cash flows.
SFAS
No. 159
In
February 2007, the FASB issued Statement No. 159, "The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115" (SFAS 159). SFAS 159 permits entities to measure
many financial instruments and certain other items at fair
value. Items eligible for the fair value measurement option include:
financial assets and financial liabilities with certain exceptions; firm
commitments that would otherwise not be recognized at inception and that involve
only financial instruments; nonfinancial insurance contracts and warranties that
the insurer can settle by paying a third party to provide those goods or
services; and host financial instruments resulting from separation of an
embedded financial derivative instrument from a nonfinancial hybrid
instrument. The fair value option may be applied instrument by
instrument, with few exceptions, is an irrevocable election and is applied only
to entire instruments. The Company will adopt SFAS 159 on January 1,
2008, and does not expect that adoption will have a material impact this
statement will have on its financial statements and results of
operations.
SFAS
141 (Revised 2007)
In
December 2007, the FASB issued SFAS 141, "Business Combinations" (SFAS
141). SFAS 141 establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141 applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. SFAS 141 applies prospectively to
business combinations with an acquisition date on or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. Early adoption is not permitted. The Company will adopt
SFAS 141 on January 1, 2009, and because the provisions of this standard are
applied prospectively, the impact to the Company cannot be determined until the
transactions occur.
SFAS
160
In
December 2007, the FASB issued SFAS 160, "Noncontrolling Interests in
Consolidated Financial Statements-an Amendment of ARB No. 51" (SFAS
160). SFAS 160 establishes accounting and reporting standards that
require that the ownership percentages in subsidiaries held by parties other
than the parent be clearly identified, labeled, and presented separately from
the parent’s equity in the equity section of the consolidated balance sheet; the
amount of consolidated net income attributable to the parent and the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement; that changes in the parent’s ownership
interest while it retains control over its subsidiary be accounted for
consistently; that when a subsidiary is deconsolidated, any retained
noncontrolling equity investment be initially measured at fair value; and that
sufficient disclosure is made to clearly identify and distinguish between the
interests of the parent and the noncontrolling owners. SFAS 160
applies to all entities that prepare consolidated financial statements, except
for non-profit entities. SFAS 160 is effective for fiscal years
beginning after December 31, 2008. Early adoption is not
permitted. The Company will adopt SFAS 160 on January 1, 2009, and is
currently assessing the impact this statement will have on its financial
statements and results of operations.
Critical Accounting
Policies
Management
is required to make judgments, assumptions, and estimates that affect the
amounts reported in the consolidated financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. Note 2 to the consolidated financial statements
describes the significant accounting policies and methods used in the
preparation of the consolidated financial statements. Certain
estimates used in the financial statements are subjective and use variables that
require judgment. These include the estimates to perform goodwill
impairments tests. The Company makes other estimates, in the course
of accounting for unbilled revenue, 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
Pursuant
to SFAS No. 142, 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 performed in accordance with SFAS 142
requires that a reporting unit’s fair value be estimated. The Company
used a discounted cash flow model to estimate the fair value of its Gas Utility
Services operating segment, and that estimated fair value was compared to its
carrying amount, including goodwill. The estimated fair value was in
excess of the carrying amount in 2007, 2006, and 2005 and therefore resulted in
no impairment.
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 based on 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, which occurs on September
30. However, the Company is in the process of moving is measurement
date to December 31. 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 the Company's pension and postretirement
plans. Vectren used the following weighted average assumptions to
develop 2007 periodic benefit cost: a discount rate of 5.85 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. During 2007, Vectren increased the discount rate by 40 basis
points to value 2007 ending pension and postretirement obligations and 2008
benefit cost due to an increase in benchmark interest rates. Future
changes in health care costs, work force demographics, interest rates, or plan
changes could significantly affect the estimated cost of these future
benefits. Management estimates that a 50 basis point decrease in the
discount rate would generally increase periodic benefit cost by approximately
$1
million.
Unbilled
Revenues
To more
closely match revenues and expenses, the Company records revenues for all gas
and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the
month to allocate unbilled units by customer class. Those allocated
units are multiplied by rates in effect during the month to calculate unbilled
revenue at balance sheet dates. While certain estimates are used in
the calculation of unbilled revenue, the method from which these estimates are
derived is not subject to near-term changes.
Regulation
At each
reporting date, the Company reviews current regulatory trends in the markets in
which it operates. This review involves judgment and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS
71). Based on the Company’s current review, it believes its
regulatory assets are probable of recovery. If all or part of the
Company's operations cease to meet the criteria of SFAS 71, a write off of
related regulatory assets and liabilities could be required. In
addition, the Company would be required to determine any impairment to the
carrying value of its utility plant and other regulated assets and
liabilities. In the unlikely event of a change in the current
regulatory environment, such write-offs and impairment charges could be
significant.
Financial
Condition
Utility
Holdings, the parent company, funds the short-term and long-term financing needs
of its consolidated operations. Vectren Corporation 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. Utility Holdings’
long-term and short-term obligations outstanding at December 31, 2007, totaled
$700 million and $386 million, respectively. Additionally, prior to
Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations
separately, and therefore, have long-term debt outstanding funded solely by
their operations. Utility Holdings’ operations have historically
funded the significant portion of Vectren’s common stock dividends.
The
credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas,
at December 31, 2007, are A-/Baa1 as rated by Standard and Poor's Ratings
Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s),
respectively. The credit ratings on SIGECO's secured debt are
A/A3. Utility Holdings’ commercial paper has a credit rating of
A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s
is stable. A security rating is not a recommendation to buy, sell, or
hold securities. The rating is subject to revision or withdrawal at
any time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade
rating is BBB- and Baa3, respectively.
The
Company’s consolidated equity capitalization objective is 45-55 percent of
long-term capitalization. This objective may have varied, and will
vary, depending on particular business opportunities, capital spending
requirements, execution of long-term financing plans and seasonal factors that
affect the Company’s operations. The Company’s equity component was
51 percent and 50 percent of long-term capitalization at December 31, 2007, and
2006, respectively. Long-term capitalization includes long-term debt,
including current maturities and debt subject to tender, as well as common
shareholder's equity.
The
Company expects the majority of its capital expenditures, investments, and debt
security redemptions to be provided by internally generated
funds. However, due to increased levels of forecasted capital
expenditures, the Company may require additional permanent
financing. The Company expects to receive proceeds from Vectren
Corporation settling an equity forward contract and plans to issue long-term
debt within the next twelve months as more fully described below. As
of December 31, 2007, the Company was in compliance with all financial
covenants.
Sources
& Uses of Liquidity
Operating Cash
Flow
The
Company's primary source of liquidity to fund working capital requirements has
been cash generated from operations, which totaled $232.2 million in 2007,
compared to $286.1 million in 2006 and $265.8 million in 2005.
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. Net income
before non-cash charges of $306.0 million increased $54.3 million compared to
$251.7 million in 2006. Working capital changes used cash of $33.7
million in 2007 compared to cash generated of $68.7 million in
2006.
The $20.3
million increase in cash generated from operations in 2006 compared to 2005 is
primarily attributable to favorable changes in working capital accounts, which
offset increases in regulatory assets and plant removal costs and a $39.5
million decrease to cash related to deferred taxes.
Financing Cash
Flow
Although
working capital requirements are generally funded by cash flow from operations,
the Company uses short-term borrowings to supplement working capital needs when
accounts receivable balances are at their highest and gas storage is
refilled. Additionally, short-term borrowings are required for
capital projects and investments until they are financed on a long-term
basis.
Cash flow
required for financing activities reflects the impact of recently executed
long-term financing, increases in common stock dividends over the periods
presented, and changes in short term borrowings. In 2007, increased
cash from financing activities was used to fund greater levels of capital
expenditures. Short-term and long-term debt proceeds and stock option
proceeds offset debt payments and dividends. In 2006, Utility
Holdings issued $100 million of senior unsecured securities and used those
proceeds to retire higher coupon long-term debt. In 2005, Utility
Holdings issued $150 million of senior unsecured securities and used those
proceeds to retire higher coupon long-term debt and refinance certain capital
projects originally financed with short-term borrowings. These
transactions are more fully described below.
SIGECO
Pollution Control Bonds
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax exempt
long-term debt. The debt has a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate will be reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation. See “Item 7A. Qualitative and
Quantitative Disclosures About Market Risk – Interest Rate Risk” for a
discussion of increased interest costs resulting from disruptions in the auction
rate markets.
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. These proceeds were
used to repay most of the $100 million outstanding balance of Utility Holdings’
7.25 percent Senior Notes originally due October 15, 2031. These
notes were redeemed on October 19, 2006 at par plus accrued
interest.
Utility Holdings 2005 Debt
Issuance
In
November 2005, Utility Holdings issued senior unsecured notes with an aggregate
principal amount of $150 million in two $75 million tranches. The
first tranche was 10-year notes due December 2015, with an interest rate of 5.45
percent priced at 99.799 percent to yield 5.47 percent to maturity (2015
Notes). The second tranche was 30-year notes due December 2035 with
an interest rate of 6.10 percent priced at 99.779 percent to yield 6.11 percent
to maturity (2035 Notes).
The notes
are guaranteed by Utility Holdings’ three public utilities: SIGECO,
Indiana Gas, and VEDO. These guarantees are full and unconditional
and joint and several. The notes have no sinking fund requirements,
and interest payments are due semi-annually. The notes may be called
by Utility Holdings, in whole or in part, at any time for an amount equal to
accrued and unpaid interest, plus the greater of 100 percent of the principal
amount or the sum of the present values of the remaining scheduled payments of
principal and interest, discounted to the redemption date on a semi-annual basis
at the Treasury Rate, as defined in the indenture, plus 20 basis points for the
2015 Notes and 25 basis points for the 2035 Notes.
In
January and June 2005, Utility Holdings entered into forward starting interest
rate swaps with a notional value of $75 million. Upon issuance of the
debt, the interest rate swaps were settled resulting in the receipt of
approximately $1.9 million in cash, which was recorded as a Regulatory liability pursuant
to existing regulatory orders. The value received is being amortized
as a reduction of interest expense over the life of the issue maturing December
2035.
The net
proceeds from the sale of the senior notes and settlement of related hedging
arrangements approximated $150 million and were used to repay short-term
borrowings and to retire approximately $50 million of long-term debt with higher
interest rates.
Long-Term
Debt Put & Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. The put or call provisions are not
triggered by specific events, but are based upon dates stated in the note
agreements, such as when notes are remarketed. During 2007, 2006 and
2005, no debt was put to the Company. Debt that may be put to the
Company within one year is classified as Long-term debt subject to
tender in current liabilities.
Utility
Holdings and Indiana Gas Debt Calls
In 2006,
the Company called at par approximately $100 million of Utility Holdings senior
unsecured notes originally due in 2031. In 2005, the Company called
at par $49.9 million of Indiana Gas insured senior unsecured notes originally
due in 2030. The notes called in 2006 and 2005 had stated interest
rates of 7.25 percent and 7.45 percent, respectively.
Other
Financing Transactions
At
December 31, 2005, $53.7 million of SIGECO notes could be put to the Company in
March of 2006, the date of their next remarketing. In March of 2006,
the notes were successfully remarketed, and are now classified in Long-term
debt. Prior to the remarketing, the notes had tax-exempt
interest rates ranging from 4.75 percent to 5.00 percent. After the
remarketing, interest rates are reset every seven days using an auction
process. See “Item
7A. Qualitative and Quantitative Disclosures About Market Risk – Interest Rate
Risk” for a discussion of increased interest costs resulting from disruptions in
the auction rate markets.
Other
debt approximating $6.5 million in 2007 was retired as scheduled.
Additional
Capital Contributions
During
the years ended December 31, 2007, 2006, and 2005, the Company has cumulatively
received additional capital of $45.3 million from Vectren. Of that
total, $40.0 million was funded by Vectren’s nonregulated operations, and $5.3
million was funded by new share issues from Vectren’s dividend reinvestment
plan.
Investing Cash
Flow
Cash flow
required for investing activities was $303.3 million in 2007, $249.9 million in
2006, and $217.7 million in 2005. Capital expenditures are the
primary component of investing activities and totaled $302.5 million in 2007,
compared to $250.0 million in 2006 and $217.8 million in 2005. The
years ended December 31, 2007 and 2006 include higher levels of expenditures for
environmental compliance equipment, and 2007 was also impacted by increased
spending for electric transmission and a new gas line serving a Honda plant
under construction in the Vectren North service territory.
Available
Sources of Liquidity
Short-term Borrowing
Arrangements
At
December 31, 2007, the Company has $520 million of short-term borrowing
capacity, of which approximately $134 million is available
Potential Capital
Contributions from Vectren
Equity
Forward
As of
December 31, 2007, Vectren Corporation has access to approximately $126 million
in proceeds generated from an SEC-registered equity offering of its common
stock. Vectren executed an equity forward sale agreement (equity
forward) in connection with the offering, and therefore, did not receive
proceeds at the time of the equity offering. The equity forward
allowed Vectren to price the offering under market conditions existing at that
time. The offering proceeds, when and if received, are expected to be
contributed to Utility Holdings and used to permanently finance its
subsidiaries’ primarily electric utility capital expenditures. The
equity forward must be settled prior to February 28,
2009.
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.
Debt Shelf
Registration
Utility
Holdings filed a shelf registration statement with the Securities and Exchange
Commission for $300 million aggregate principal amount of unsecured senior notes
in September 2007, which is anticipated to meet Utility Holdings’ estimated debt
financing requirements over the next 3 years. In October 2007 the SEC
declared the registration statement to be effective. When issued, the
unsecured notes will be guaranteed by Utility Holdings’ three operating utility
companies: SIGECO, Indiana Gas, and VEDO. These guarantees of
Utility Holdings’ debt will be full and unconditional and joint and
several. In contemplation of a 2008 issuance, the Company executed
forward starting interest rate swaps with a total notional amount of $80 million
that expire in 2008.
Known
& Potential Future Uses of Liquidity
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2007:
|
Total
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
||||||||||||||||||||||
|
Long-term
debt (1)
|
$ | 1,066.2 | $ | - | $ | - | $ | - | $ | 250.0 | $ | - | $ | 816.2 | ||||||||||||||
|
Short-term
debt
|
385.9 | 385.9 | - | - | - | - | - | |||||||||||||||||||||
|
Long-term
debt interest commitments
|
864.6 | 64.2 | 64.2 | 64.2 | 62.8 | 47.6 | 561.6 | |||||||||||||||||||||
|
Plant
purchase commitments (2)
|
40.6 | 36.6 | 4.0 | - | - | - | - | |||||||||||||||||||||
|
Operating
leases
|
1.4 | 0.6 | 0.2 | 0.5 | 0.1 | - | - | |||||||||||||||||||||
|
Total
(3)
|
$ | 2,358.7 | $ | 487.3 | $ | 68.4 | $ | 64.7 | $ | 312.9 | $ | 47.6 | $ | 1,377.8 | ||||||||||||||
|
(1)
|
Certain
long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions
allow holders to put debt back to the Company at face value or the Company
to call debt at face value or at a premium. Long-term debt
subject to tender during the years following 2007 (in millions) is zero in
2008, $80.0 in 2009, $10.0 million in 2010, $30.0 in 2011 and zero in 2012
and thereafter.
|
|
(2)
|
The
settlement period of these utility plant obligations is
estimated.
|
|
(3)
|
The
Company has $3.8 million in unrecognized tax benefits for which the
expected settlement date cannot be
estimated.
|
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase natural gas and electricity as well as certain transportation and
storage rights. Costs arising from these commitments, while
significant, are pass-through costs, generally collected dollar-for-dollar from
retail customers through regulator approved cost recovery
mechanisms. Because of the pass through nature of these costs and
their insignificant impact to earnings, they have not been included in the
listing of contractual obligations.
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax exempt auction rate mode long term debt that the Company
will convert that debt from its current auction rate mode into a daily interest
rate mode during March 2008. The debt will be subject to mandatory tender
for purchase on the conversion date at 100 percent of the principal amount plus
accrued interest.
Planned Capital
Expenditures
The
timing and amount of planned capital expenditures, including contractual
purchase commitments discussed above, for the five-year period 2008 - 2012 are
estimated as follows (in millions): $312 in 2008, $282 in 2009, $296
in 2010, $229 in 2011, and $208 in 2012.
Pension and Postretirement
Funding Obligations
Vectren
believes making contributions to its qualified pension plans in the coming years
will be necessary. Vectren’s management currently estimates that the
qualified pension plans will require contributions of approximately $10 and $8
million in 2008 and 2009, a portion of which may be funded by Utility
Holdings. During 2007, Vectren made contributions of approximately
$17 million, of which $1.9 million were funded by Utility Holdings.
Off Balance Sheet
Arrangements
As of
December 31, 2007, the Company does not have any material off balance sheet
arrangements.
Ratings
Triggers
None of
Utility Holdings’ currently outstanding debt arrangements contain ratings
triggers.
Forward-Looking
Information
A
“safe harbor” for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The
Reform Act of 1995 was adopted to encourage such forward-looking statements
without the threat of litigation, provided those statements are identified as
forward-looking and are accompanied by meaningful cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Certain matters
described in Management’s Discussion and Analysis of Results of Operations and
Financial Condition are forward-looking statements. Such statements
are based on management’s beliefs, as well as assumptions made by and
information currently available to management. When used in this
filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”,
“objective”, “projection”, “forecast”, “goal” and similar expressions are
intended to identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause the Company’s actual
results to differ materially from those contemplated in any forward-looking
statements include, among others, the following:
|
·
|
Factors
affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
transportation and storage costs, or availability due to higher demand,
shortages, transportation problems or other developments; environmental or
pipeline incidents; transmission or distribution incidents; unanticipated
changes to electric energy supply costs, or availability due to demand,
shortages, transmission problems or other developments; or electric
transmission or gas pipeline system
constraints.
|
|
·
|
Increased
competition in the energy industry, including the effects of industry
restructuring and unbundling.
|
|
·
|
Regulatory
factors such as unanticipated changes in rate-setting policies or
procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate
increases.
|
|
·
|
Financial,
regulatory or accounting principles or policies imposed by the Financial
Accounting Standards Board; the Securities and Exchange Commission; the
Federal Energy Regulatory Commission; state public utility commissions;
state entities which regulate electric and natural gas transmission and
distribution, natural gas gathering and processing, electric power supply;
and similar entities with regulatory
oversight.
|
|
·
|
Economic
conditions including the effects of an economic downturn, inflation rates,
commodity prices, and monetary
fluctuations.
|
|
·
|
Increased
natural gas commodity prices and the potential impact on customer
consumption, uncollectible accounts expense, unaccounted for gas and
interest expense.
|
|
·
|
Changing
market conditions and a variety of other factors associated with physical
energy and financial trading activities including, but not limited to,
price, basis, credit, liquidity, volatility, capacity, interest rate, and
warranty risks.
|
|
·
|
Direct
or indirect effects on the Company’s business, financial condition,
liquidity and results of operations resulting from changes in credit
ratings, changes in interest rates, and/or changes in market perceptions
of the utility industry and other energy-related
industries.
|
|
·
|
Employee
or contractor workforce factors including changes in key executives,
collective bargaining agreements with union employees, aging workforce
issues, or work stoppages.
|
|
·
|
Legal
and regulatory delays and other obstacles associated with mergers,
acquisitions and investments in joint
ventures.
|
|
·
|
Costs,
fines, penalties and other effects of legal and administrative
proceedings, settlements, investigations and claims, including, but
not limited to, such matters involving compliance with state and federal
laws and interpretations of these
laws.
|
|
·
|
Changes
in federal, state or local legislative requirements, such as changes in
tax laws or rates, environmental laws, including laws governing greenhouse
gases, mandates of sources of renewable energy, and other
regulations.
|
The
Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM
7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET
RISK
The
Company is exposed to various business risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures
are monitored and managed by the Company as an integral part of its overall risk
management program. The Company’s risk management program includes,
among other things, the use of derivatives. The Company may also
execute derivative contracts in the normal course of operations while buying and
selling commodities to be used in operations and optimizing its generation
assets.
|
The
Company has in place a risk management committee that consists of senior
management as well as financial and operational management. The
committee is actively involved in identifying risks as well as reviewing
and authorizing risk mitigation
strategies.
|
Commodity
Price Risk
Regulated
Operations
The
Company’s regulated operations have limited exposure to commodity price risk for
transactions involving purchases and sales of natural gas and electricity for
the benefit of retail customers due to current Indiana and Ohio regulations,
which subject to compliance with those regulations, allow for recovery of the
cost of such purchases through natural gas and fuel cost adjustment
mechanisms. Constructive regulatory orders, such as that authorizing
lost margin recovery and recovery of unaccounted for gas and other gas related
expenses, also mitigate the effect volatile gas costs may have on the Company’s
financial condition.
Although
Vectren’s regulated operations are exposed to limited commodity price risk,
volatile natural gas prices have other effects such as higher working capital
requirements, higher interest costs, and some level of price-sensitivity in
volumes sold or delivered. The Company will manage these risks by
executing derivative contracts that hedge the price of forecasted natural gas
purchases. These contracts are subject to regulation which allows for
reasonable and prudent hedging costs to be recovered through
rates. Therefore, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
Wholesale Power
Marketing
The
Company’s wholesale power marketing activities include asset optimization
strategies that manage the utilization of available electric generating
capacity. These optimization strategies involve the sale of excess
generation into the MISO Day Ahead and Real-time markets. As part of
these strategies, the Company may also execute energy contracts that commit the
Company to purchase and sell electricity in the future. Commodity
price risk results from forward positions that commit the Company to deliver
electricity. The Company mitigates price risk exposure with planned
unutilized generation capability and offsetting forward purchase
contracts. The Company accounts for asset optimization contracts that
are derivatives at fair value with the offset marked to market through
earnings. No market sensitive derivative positions were outstanding
on December 31, 2007 and 2006.
Sales to
Municipalities
The
Company purchases and sells electricity to meet the demands of certain
municipalities. Price risk from forward positions obligating the
Company to deliver commodities is mitigated with generating capability and
offsetting forward purchase contracts. These contracts are expected
to be settled by physical receipt or delivery of the commodity.
Interest
Rate Risk
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on interest
expense. The Company manages this risk by allowing an annual average
of 20 percent and 30 percent of its total debt to be exposed to variable rate
volatility. However, this targeted range may be exceeded during the
seasonal increases in short-term borrowing. To manage this exposure,
the Company may use derivative financial instruments.
Market
risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2007 and 2006, the weighted average
combined borrowings under these arrangements approximated $340.4 million and
$263.6 million, respectively. At December 31, 2007 and 2006, combined
borrowings under these arrangements were $489.0 million and $351.7 million,
respectively. Based upon average borrowing rates under these
facilities during the years ended December 31, 2007 and 2006, an increase of 100
basis points (one percentage point) in the rates would have increased interest
expense by $3.4 million and $2.6 million, respectively.
At
December 31, 2007, SIGECO has approximately $103 million of tax-exempt
adjustable rate long-term debt where the interest rates on this debt are reset
every seven days through an auction process. Throughout 2007, the weighted
average interest rate associated with this debt was 4.15 percent. If these
auctions were to fail, interest rates would reset to the maximum rates permitted
under the various debt indentures of 10 percent to 15 percent for the following
week. On a weekly basis, interest expense using these maximum rates would
be approximately $200,000 higher than the average weekly interest expense based
on rates experienced during 2007. No SIGECO auctions failed during 2007
nor have they during the period since Vectren was formed in 2000.
However,
in February 2008, significant disruptions occurred in the overall auction rate
debt markets. As a result, many auctions of tax exempt debt, including
some of those involving SIGECO's auction rate debt, failed as a result of
insufficient order interest from potential investors. These failures
are largely attributable to a lack of liquidity in the market place arising from
downgrades in, and negative watches regarding, credit ratings of monoline
insurers that guarantee the timely repayment of bond principal and interest if
an issuer defaults as well as from disruptions in the overall financial
markets. Monoline insurer Ambac Assurance Corporation insures the
Company's auction rate long-term debt. As a result of these failed
auctions, the Company has experienced, and may continue to experience, increased
interest costs.
Subject
to applicable notice provisions, SIGECO may, at its option, redeem this auction
rate debt at par value plus the accrued and unpaid interest or elect to utilize
other interest rate modes available to it as defined in the various debt
indentures. SIGECO provided notice to current holders of this debt during
late February 2008 that such debt will be converted from the auction rate mode
into a daily interest rate mode during March 2008 and will be subject to
mandatory tender for purchase on the conversion date at 100 percent of the
principal amount plus accrued interest. Following conversion to the
daily mode, expected to be completed by March 14, SIGECO may again convert the
debt to other interest rate modes and remarket it to investors or redeem the
debt and reissue new debt, including the possibility of replacing the
outstanding debt with taxable debt from Utility Holdings.
Other
Risks
By using
forward purchase contracts and derivative 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 a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its
receivables by continually reviewing creditworthiness and requests cash deposits
or refunds cash deposits based on that review. Credit risk associated
with certain investments is also managed by a review of creditworthiness and
receipt of collateral. In addition, credit risk is mitigated by
regulatory orders that allow recovery of all bad debt expense in Ohio and the
gas cost portion of bad debt expense in Indiana.
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S RESPONSIBILITY
FOR THE FINANCIAL STATEMENTS
Vectren
Utility Holdings, Inc.’s management is responsible for establishing and
maintaining adequate internal controls over financial
reporting. Those control procedures underlie the preparation of the
consolidated balance sheets, statements of income, cash flows, and common
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,
2007. Management certified this fact in its Sarbanes Oxley Section
302 certifications, which are attached as exhibits to this 2007 Form
10-K.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
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, 2007
and 2006, 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, 2007. Our audits also included the financial
statement schedule included in the Index at Item 15. These
financial statements and financial statement schedule are the responsibility of
the Company’s management. Our responsibility is to express an opinion
on the financial statements and financial statement schedule based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. 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, 2007 and 2006, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2007, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
DELOITTE
& TOUCHE LLP
Indianapolis,
Indiana
February
19, 2008
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
At December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
& cash equivalents
|
$ | 11.7 | $ | 28.5 | ||||
|
Accounts
receivable - less reserves of $2.7 &
|
||||||||
|
$2.5,
respectively
|
137.1 | 134.8 | ||||||
|
Receivables
due from other Vectren companies
|
17.9 | 0.3 | ||||||
|
Accrued
unbilled revenues
|
140.6 | 121.4 | ||||||
|
Inventories
|
134.9 | 141.9 | ||||||
|
Recoverable
fuel & natural gas costs
|
- | 1.8 | ||||||
|
Prepayments
& other current assets
|
93.3 | 103.2 | ||||||
|
Total
current assets
|
535.5 | 531.9 | ||||||
|
Utility
Plant
|
||||||||
|
Original
cost
|
4,062.9 | 3,820.2 | ||||||
|
Less: accumulated
depreciation & amortization
|
1,523.2 | 1,434.7 | ||||||
|
Net
utility plant
|
2,539.7 | 2,385.5 | ||||||
|
Investments
in unconsolidated affiliates
|
0.2 | 0.2 | ||||||
|
Other
investments
|
24.7 | 21.4 | ||||||
|
Nonutility
property - net
|
176.2 | 163.1 | ||||||
|
Goodwill
- net
|
205.0 | 205.0 | ||||||
|
Regulatory
assets
|
151.7 | 116.8 | ||||||
|
Other
assets
|
10.7 | 16.9 | ||||||
|
TOTAL
ASSETS
|
$ | 3,643.7 | $ | 3,440.8 | ||||
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,
|
||||||||
|
2007
|
2006
|
|||||||
|
LIABILITIES &
SHAREHOLDER'S EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable
|
$ | 138.7 | $ | 136.2 | ||||
|
Accounts
payable to affiliated companies
|
66.9 | 68.2 | ||||||
|
Payables
to other Vectren companies
|
34.2 | 25.3 | ||||||
|
Refundable
fuel & natural gas costs
|
27.2 | 35.3 | ||||||
|
Accrued
liabilities
|
138.9 | 115.8 | ||||||
|
Short-term
borrowings
|
385.9 | 270.1 | ||||||
|
Current
maturities of long-term debt
|
- | 6.5 | ||||||
|
Long-term
debt subject to tender
|
- | 20.0 | ||||||
|
Total
current liabilities
|
791.8 | 677.4 | ||||||
|
Long-Term
Debt - Net of Current Maturities &
|
||||||||
|
Debt
Subject to Tender
|
1,062.6 | 1,025.3 | ||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||
|
Deferred
income taxes
|
286.9 | 282.2 | ||||||
|
Regulatory
liabilities
|
307.2 | 291.1 | ||||||
|
Deferred
credits & other liabilities
|
104.8 | 108.1 | ||||||
|
Total
deferred credits & other liabilities
|
698.9 | 681.4 | ||||||
|
Commitments
& Contingencies (Notes 7 - 10)
|
||||||||
|
|
||||||||
|
Common
Shareholder's Equity
|
||||||||
|
Common
stock (no par value)
|
638.2 | 632.9 | ||||||
|
Retained
earnings
|
451.9 | 422.9 | ||||||
|
Accumulated
other comprehensive income
|
0.3 | 0.9 | ||||||
|
Total
common shareholder's equity
|
1,090.4 | 1,056.7 | ||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,643.7 | $ | 3,440.8 | ||||
|
|
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, except per share amounts)
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,269.4 | $ | 1,232.5 | $ | 1,359.7 | ||||||
|
Electric
utility
|
487.9 | 422.2 | 421.4 | |||||||||
|
Other
|
1.7 | 1.8 | 0.7 | |||||||||
|
Total
operating revenues
|
1,759.0 | 1,656.5 | 1,781.8 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
847.2 | 841.5 | 973.3 | |||||||||
|
Cost
of fuel & purchased power
|
174.8 | 151.5 | 144.1 | |||||||||
|
Other
operating
|
266.1 | 239.0 | 241.3 | |||||||||
|
Depreciation
& amortization
|
158.4 | 151.3 | 141.3 | |||||||||
|
Taxes
other than income taxes
|
68.1 | 64.2 | 65.2 | |||||||||
|
Total
operating expenses
|
1,514.6 | 1,447.5 | 1,565.2 | |||||||||
|
OPERATING
INCOME
|
244.4 | 209.0 | 216.6 | |||||||||
|
Other
income - net
|
9.4 | 7.6 | 5.9 | |||||||||
|
Interest
expense
|
80.6 | 77.5 | 69.9 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
173.2 | 139.1 | 152.6 | |||||||||
|
Income
taxes
|
66.7 | 47.7 | 57.5 | |||||||||
|
NET
INCOME
|
$ | 106.5 | $ | 91.4 | $ | 95.1 | ||||||
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net
income
|
$ | 106.5 | $ | 91.4 | $ | 95.1 | ||||||
|
Adjustments
to reconcile net income to cash from operating activities:
|
||||||||||||
|
Depreciation & amortization
|
158.4 | 151.3 | 141.3 | |||||||||
|
Deferred income taxes & investment tax credits
|
14.4 | (6.4 | ) | 33.1 | ||||||||
|
Expense
portion of pension & postretirement periodic benefit
cost
|
4.1 | 4.2 | 4.0 | |||||||||
|
Provision for uncollectible accounts
|
15.0 | 13.6 | 14.4 | |||||||||
|
Other non-cash (income) expense - net
|
7.6 | (2.4 | ) | 1.3 | ||||||||
|
Changes in working capital accounts:
|
||||||||||||
|
Accounts
receivable, including to Vectren companies & accrued unbilled
revenue
|
(54.1 | ) | 115.3 | (88.1 | ) | |||||||
|
Inventories
|
7.0 | (15.7 | ) | (68.2 | ) | |||||||
|
Recoverable/refundable fuel & natural gas
costs
|
(6.3 | ) | 41.3 | 3.6 | ||||||||
|
Prepayments & other current assets
|
4.0 | 16.7 | 23.3 | |||||||||
|
Accounts
payable, including to Vectren companies & affiliated
companies
|
14.6 | (74.7 | ) | 100.7 | ||||||||
|
Accrued liabilities
|
1.1 | (14.2 | ) | 15.7 | ||||||||
|
Changes in noncurrent assets
|
(22.3 | ) | (27.2 | ) | (8.4 | ) | ||||||
|
Changes in noncurrent
liabilities
|
(17.8 | ) | (7.1 | ) | (2.0 | ) | ||||||
|
Net
cash flows from operating activities
|
232.2 | 286.1 | 265.8 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Long-term
debt - net of issuance costs & hedging proceeds
|
16.3 | 92.8 | 150.0 | |||||||||
|
Additional
capital contribution
|
5.3 | 20.0 | 20.0 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Dividends
to parent
|
(76.6 | ) | (75.4 | ) | (80.7 | ) | ||||||
|
Retirement
of long-term debt
|
(6.5 | ) | (100.0 | ) | (49.9 | ) | ||||||
|
Redemption
of preferred stock of subsidiary
|
- | - | (0.1 | ) | ||||||||
|
Net
change in short-term borrowings, including from other
|
||||||||||||
|
Vectren
companies
|
115.8 | 43.2 | (81.4 | ) | ||||||||
|
Net
cash flows from financing activities
|
54.3 | (19.4 | ) | (42.1 | ) | |||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds
from other investing activities
|
1.0 | 0.1 | 0.1 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(302.5 | ) | (250.0 | ) | (217.8 | ) | ||||||
|
Other
investments
|
(1.8 | ) | - | - | ||||||||
|
Net
cash flows from investing activities
|
(303.3 | ) | (249.9 | ) | (217.7 | ) | ||||||
|
Net
change in cash & cash equivalents
|
(16.8 | ) | 16.8 | 6.0 | ||||||||
|
Cash
& cash equivalents at beginning of period
|
28.5 | 11.7 | 5.7 | |||||||||
|
Cash
& cash equivalents at end of period
|
$ | 11.7 | $ | 28.5 | $ | 11.7 | ||||||
|
Cash
paid during the year for:
|
||||||||||||
|
Interest
|
$ | 77.1 | $ | 75.2 | $ | 65.9 | ||||||
|
Income taxes
|
44.9 | 49.8 | 43.3 | |||||||||
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, except per share amounts)
|
Accumulated
|
||||||||||||||||
|
Other
|
||||||||||||||||
|
Common
|
Retained
|
Comprehensive
|
||||||||||||||
|
Stock
|
Earnings
|
Income
(Loss)
|
Total
|
|
||||||||||||
|
|
||||||||||||||||
|
Balance
at January 1, 2005
|
$ | 592.9 | $ | 392.5 | $ | - | $ | 985.4 | ||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
95.1 | 95.1 | ||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
Unrealized
gains - net of $2.9 million in tax
|
4.2 | 4.2 | ||||||||||||||
|
Reclassification to net income - net of $0.2 million in
tax
|
(0.2 | ) | (0.2 | ) | ||||||||||||
|
Total
comprehensive income
|
95.1 | 4.0 | 99.1 | |||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
20.0 | 20.0 | ||||||||||||||
|
Dividends
|
(80.7 | ) | (80.7 | ) | ||||||||||||
|
Balance
at December 31, 2005
|
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
|
91.4 | (3.1 | ) | 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
|
(0.6 | ) | 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 | ||||||||
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, and serves 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. Both Vectren and
Utility Holdings are holding companies as defined by the Energy Policy Act of
2005 (Energy Act). Vectren was incorporated under the laws of Indiana
on June 10, 1999.
Indiana
Gas provides energy delivery services to over 568,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 112,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and
SIGECO generally do business as Vectren Energy Delivery of
Indiana. The Ohio operations provide energy delivery services to
approximately 318,000 natural gas customers located near Dayton in west central
Ohio. The Ohio operations are owned as a tenancy in common by Vectren
Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility
Holdings (53 percent ownership), and Indiana Gas (47 percent
ownership). The Ohio operations generally do business as Vectren
Energy Delivery of Ohio.
|
2.
|
Summary
of Significant Accounting Policies
|
|
A.
|
Principles
of Consolidation
|
The
consolidated financial statements include the accounts of the Company and its
wholly owned subsidiaries, after elimination of significant intercompany
transactions.
|
B.
|
Cash
& Cash Equivalents
|
All
highly liquid investments with an original maturity of three months or less at
the date of purchase are considered cash equivalents.
|
C.
|
Inventories
|
Inventories consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Gas
in storage – at average cost
|
$ | 63.7 | $ | 61.3 | ||||
|
Materials
& supplies
|
31.3 | 28.0 | ||||||
|
Gas
in storage – at LIFO cost
|
16.7 | 26.5 | ||||||
|
Fuel
(coal & oil) for electric generation
|
23.2 | 26.0 | ||||||
|
Other
|
- | 0.1 | ||||||
|
Total
inventories
|
$ | 134.9 | $ | 141.9 | ||||
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, 2007, and 2006,
by approximately $73.0 million and $79.0 million, respectively. Gas
in storage of the Indiana regulated operations is stated at LIFO. All
other inventories are carried at average cost.
|
D.
|
Utility
Plant & Depreciation
|
Utility plant is stated at
historical cost, including AFUDC. Depreciation rates are established
through regulatory proceedings and are applied to all in-service utility
plant. The original cost of utility plant, together with depreciation
rates expressed as a percentage of original cost, follows:
|
At
December 31,
|
||||||||||||||||
|
(In
millions)
|
2007
|
2006
|
||||||||||||||
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|||||||||||||
|
Gas
utility plant
|
$ | 2,077.5 | 3.6 | % | $ | 1,956.1 | 3.6 | % | ||||||||
|
Electric
utility plant
|
1,815.8 | 3.3 | % | 1,685.5 | 3.4 | % | ||||||||||
|
Common
utility plant
|
45.5 | 2.8 | % | 45.2 | 3.0 | % | ||||||||||
|
Construction
work in progress
|
124.1 | - | 133.4 | - | ||||||||||||
|
Total
original cost
|
$ | 4,062.9 | $ | 3,820.2 | ||||||||||||
AFUDC represents the cost of borrowed and equity funds which are used for construction purposes, and charged to construction work in progress during the construction period. AFUDC is included in Other – net in the Consolidated Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
AFUDC
– borrowed funds
|
$ | 3.5 | $ | 2.6 | $ | 1.6 | ||||||
|
AFUDC
– equity funds
|
0.5 | 1.5 | 0.3 | |||||||||
|
Total
AFUDC
|
$ | 4.0 | $ | 4.1 | $ | 1.9 | ||||||
Maintenance
and repairs, including the cost of removal of minor items of property and
planned major maintenance projects, are charged to expense as
incurred. When property that represents a retirement unit is replaced
or removed, the remaining historical value of such property is charged to Utility plant, with an
offsetting charge to Accumulated
depreciation. Costs to dismantle and remove retired property
are recovered through the depreciation rates identified above.
Jointly Owned
Plant
SIGECO
owns 50 percent of the 300 MW Unit 4 at the Warrick Power Plant as tenants in
common with Alcoa Generating Corporation (AGC), a subsidiary of
ALCOA. SIGECO's share of the cost of this unit at December 31, 2007
is $63.5 million with accumulated depreciation totaling $46.6
million. The construction work-in-progress balance associated with
SIGECO’s ownership interest totaled $56.4 million at December 31,
2007. AGC and SIGECO also share equally in the cost of operation and
output of the unit. SIGECO's share of operating costs is included in
Other operating
expenses in the Consolidated Statements of Income.
|
E.
|
Nonutility
Property
|
Nonutility property, net of
accumulated depreciation and amortization follows:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Computer
hardware & software
|
$ | 114.5 | $ | 105.4 | ||||
|
Land
& buildings
|
48.5 | 44.9 | ||||||
|
All
other
|
13.2 | 12.8 | ||||||
|
Nonutility
property - net
|
$ | 176.2 | $ | 163.1 | ||||
The depreciation of nonutility property is charged against income over its estimated useful life (ranging from 3.5 to 40 years), using the straight-line method of depreciation. 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 $135.2 million and $113.7 million as of December 31, 2007, and 2006, respectively. For the years ended December 31, 2007, 2006, and 2005, the Company capitalized interest totaling $1.3 million, $0.7 million and $0.6 million, respectively, on nonutility plant construction projects.
|
F.
|
Goodwill
|
Goodwill
arising from business combinations is accounted for in accordance with SFAS No.
142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142
requires a portion of goodwill be charged to expense only when it is
impaired. The Company tests its goodwill for impairment at a
reporting unit level at least annually and that test is performed at the
beginning of each year. Impairment reviews consist of a comparison of
the fair value of a reporting unit to its carrying amount. If the
fair value of a reporting unit is less than its carrying amount, an impairment
loss is recognized in operations. Through December 31, 2007, no
goodwill impairments have been recorded. All of the Company’s
goodwill is included in the Gas Utility Services operating segment.
|
G.
|
Intangible
Assets
|
The
Company has emission allowances relating to its wholesale power marketing
operations totaling $2.6 million and $4.2 million at December 31, 2007 and 2006,
respectively. The value of the emission allowances are recognized as
they are consumed or sold on the open market.
|
H.
|
Regulation
|
Retail
public utility operations affecting Indiana customers are subject to regulation
by the IURC, and retail public utility operations affecting Ohio customers are
subject to regulation by the PUCO. The Company’s accounting policies
give recognition to the rate-making and accounting practices of these agencies
and to accounting principles generally accepted in the United States, including
the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation” (SFAS 71).
Refundable
or Recoverable Gas Costs and Cost of Fuel & Purchased Power
All
metered gas rates contain a gas cost adjustment clause that allows the Company
to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel. The net
energy cost of purchased power, subject to an agreed upon benchmark, is also
recovered through regulatory proceedings. The Company records any
under-or-over-recovery resulting from gas and fuel adjustment clauses each month
in revenues. A corresponding asset or liability is recorded until the
under or over-recovery is billed or refunded to utility
customers. The cost of gas sold is charged to operating expense as
delivered to customers, and the cost of fuel for electric generation is charged
to operating expense when consumed.
Regulatory
Assets and Liabilities
Regulatory
assets represent probable future revenues associated with certain incurred
costs, which will be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable expenditures by
the Company for removal costs or future reductions in revenues associated with
amounts that are to be credited to customers through the ratemaking
process. The Company assesses the recoverability of costs recognized
as regulatory assets and liabilities and the ability to continue to account for
its activities based on the criteria set forth in SFAS 71. Based on
current regulation, the Company believes such accounting is
appropriate. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be
required to determine any impairment to the carrying value of its utility plant
and other regulated assets.
Regulatory Assets consist of
the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Future
amounts recoverable from ratepayers:
|
||||||||
|
Income
taxes
|
$ | 14.0 | $ | 13.3 | ||||
|
Interest
rate derivatives
|
8.9 | - | ||||||
|
Asset
retirement obligations & other
|
10.9 | 1.9 | ||||||
| 33.8 | 15.2 | |||||||
|
Amounts
deferred for future recovery:
|
||||||||
|
Demand
side management programs
|
- | 27.7 | ||||||
|
MISO-related
costs
|
- | 17.1 | ||||||
|
Cost
recovery riders & other
|
1.9 | 4.7 | ||||||
| 1.9 | 49.5 | |||||||
|
Amounts
currently recovered in customer rates related to:
|
||||||||
|
Demand
side management programs
|
27.6 | 1.5 | ||||||
|
Unamortized
debt issue costs & hedging proceeds
|
25.0 | 26.4 | ||||||
|
Indiana
authorized trackers
|
21.5 | 6.1 | ||||||
|
MISO-related
costs
|
20.8 | - | ||||||
|
Ohio
authorized trackers
|
10.4 | 10.4 | ||||||
|
Premiums
paid to reacquire debt & other
|
10.7 | 7.7 | ||||||
| 116.0 | 52.1 | |||||||
|
Total
regulatory assets
|
$ | 151.7 | $ | 116.8 | ||||
Of the $116.0 million currently being recovered in customer rates charged to customers, $27.6 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 8 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.
Regulatory
Liabilities
At
December 31, 2007 and 2006, the Company has approximately $307.2 million and
$291.1 million, respectively, in regulatory liabilities. Of these
amounts, $288.3 million and $270.6 million relate to cost of removal
obligations.
The
Company collects an estimated cost of removal of its utility plant through
depreciation rates established in regulatory proceedings. The Company
records amounts expensed in advance of payments as a Regulatory liability because
the liability does not meet the threshold of an asset retirement obligation as
defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its
related interpretations (SFAS 143).
|
I.
|
Asset
Retirement Obligations
|
A portion
of removal costs related to interim retirements of gas utility pipeline and
utility poles, certain asbestos-related issues, and reclamation activities meet
the definition of an asset retirement obligation (ARO). SFAS No. 143
requires entities to record the fair value of a liability for a legal ARO in the
period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the
related long-lived asset. 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 $16.4 million and $18.3 million at December 31, 2007
and 2006, respectively. At December 31, 2007, a $9.5 million ARO is
included in Accrued
liabilities. During 2007, the Company recorded accretion of
$1.0 million and increases in estimates of $6.6 million. During 2006,
the Company recorded accretion of $1.0 million with no changes in
estimates.
|
J.
|
Impairment
Review of Long-Lived Assets
|
Long-lived
assets are reviewed as facts and circumstances indicate that the carrying amount
may be impaired. This review is performed in accordance with SFAS No.
144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS
144). SFAS 144 establishes one accounting model for all impaired
long-lived assets and long-lived assets to be disposed of by sale or
otherwise. SFAS 144 requires that the evaluation for impairment
involve the comparison of an asset’s carrying value to the estimated future cash
flows that the asset is expected to generate over its remaining
life. If this evaluation were to conclude that the carrying value of
the asset is impaired, an impairment charge would be recorded based on the
difference between the asset’s carrying amount and its fair value (less costs to
sell for assets to be disposed of by sale) as a charge to operations or
discontinued operations.
|
K.
|
Comprehensive
Income
|
Comprehensive
income is a measure of all changes in equity that result from the
non-shareholder transactions. This information is reported in the
Consolidated Statements of Common Shareholder’s Equity. A summary of
the components of and changes in Accumulated other comprehensive
income for the past three years follows:
|
2005
|
2006
|
2007
|
||||||||||||||||||||||||||
|
Beginning
|
Changes
|
End
|
Changes
|
End
|
Changes
|
End
|
||||||||||||||||||||||
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
||||||||||||||||||||||
|
(In
millions)
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
|||||||||||||||||||||
|
Cash
flow hedges
|
- | 6.7 | 6.7 | (5.3 | ) | 1.4 | (0.9 | ) | 0.5 | |||||||||||||||||||
|
Deferred
income taxes
|
- | (2.7 | ) | (2.7 | ) | 2.2 | (0.5 | ) | 0.3 | (0.2 | ) | |||||||||||||||||
|
Accumulated
other comprehensive income (loss)
|
$ | - | $ | 4.0 | $ | 4.0 | $ | (3.1 | ) | $ | 0.9 | $ | (0.6 | ) | $ | 0.3 | ||||||||||||
|
L.
|
Revenues
|
Revenues
are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.
|
M.
|
Excise
and Utility Receipts Taxes
|
Excise
taxes and a portion of utility receipts taxes are included in rates charged to
customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $41.8 million in 2007, $39.7
million in 2006, and $42.6 million in 2005. Expense associated with
excise and utility receipts taxes are recorded as a component of Taxes other than income
taxes.
|
N.
|
Use
of Estimates
|
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these
estimates.
|
O.
|
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 fuel used for electric generation. The
coal sold by Vectren Fuels to SIGECO is priced consistent with letter agreements
with the OUCC. Amounts paid for such purchases for the years ended
December 31, 2007, 2006, and 2005, totaled $115.9 million, $116.8 million, and
$96.4 million, respectively. Amounts owed to Vectren Fuels at
December 31, 2007 and 2006 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
$46.9 million in 2007, $20.6 million in 2006, and $13.6 million in
2005. Amounts owed to Miller at December 31, 2007 and 2006 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 based on cost. Utility
Holdings received corporate allocations totaling $47.1 million, $43.7 million,
and $48.0 million for the years ended December 31, 2007, 2006, and 2005,
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 expense 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, 2007, 2006, and 2005, periodic pension costs totaling
$5.2 million, $5.3 million, and $4.8 million, respectively, were directly
charged by Vectren to the Company. For the years ended December 31,
2007, 2006, and 2005, other periodic postretirement benefit costs totaling $0.5
million, $0.6 million, and $0.8 million, respectively, were directly charged by
Vectren to the Company. As of December 31, 2007 and 2006, $37.4
million and $44.2 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. At December 31, 2006, $5.9 million is
included in Other
assets for amounts funded in advance to Vectren.
Cash Management
Arrangements
The
Company participates in Vectren’s centralized cash management
program.
Share-Based Incentive
Plans
FASB
Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) requires
compensation costs related to all share-based payment transactions to be
recognized in the financial statements. Compensation cost is
recognized over the period that an employee provides service in exchange for a
share based award. SFAS 123R replaced SFAS 123 and superseded APB
25. The Company adopted SFAS 123R using the modified prospective
method on January 1, 2006. The adoption of this standard, and
subsequent interpretations of the standard, did not have a material effect on
the Company’s operating results or financial condition. 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.
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
components of income tax expense and utilization of investment tax credits
follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 43.7 | $ | 43.3 | $ | 15.7 | ||||||
|
State
|
8.6 | 10.8 | 8.7 | |||||||||
|
Total
current taxes
|
52.3 | 54.1 | 24.4 | |||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
11.9 | (0.9 | ) | 32.2 | ||||||||
|
State
|
4.2 | (3.5 | ) | 3.3 | ||||||||
|
Total
deferred taxes
|
16.1 | (4.4 | ) | 35.5 | ||||||||
|
Amortization
of investment tax credits
|
(1.7 | ) | (2.0 | ) | (2.4 | ) | ||||||
|
Total
income tax expense
|
$ | 66.7 | $ | 47.7 | $ | 57.5 | ||||||
The
liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates. Significant components of the net deferred tax
liability follow:
|
At
December 31,
|
|||||||||||
|
(In
millions)
|
2007
|
2006
|
|||||||||
|
Noncurrent
deferred tax liabilities (assets):
|
|||||||||||
| Depreciation & cost recovery timing differences |
|
$ | 279.7 | $ | 271.8 | ||||||
| Regulatory assets recoverable through future rates |
|
20.3 | 21.0 | ||||||||
|
Demand
side management programs
|
|
7.9 | 8.4 | ||||||||
|
Other
comprehensive income
|
|
0.3 | 0.5 | ||||||||
|
Employee
benefit obligations
|
|
(19.7 | ) | (24.4 | ) | ||||||
|
Regulatory
liabilities to be settled through future rates
|
|
(6.3 | ) | (7.7 | ) | ||||||
|
Other –
net
|
|
4.7 | 12.6 | ||||||||
|
Net
noncurrent deferred tax liability
|
|
286.9 | 282.2 | ||||||||
|
Current
deferred tax liabilities:
|
|||||||||||
|
Deferred fuel
costs - net
|
|
(1.4 | ) | (1.9 | ) | ||||||
|
Other –
net
|
|
6.3 | (1.6 | ) | |||||||
| Net deferred tax liability |
|
$ | 291.8 | $ | 278.7 | ||||||
At
December 31, 2007, and 2006, investment tax credits totaling $8.2 million and
$9.9 million, respectively, are included in Deferred credits and other
liabilities. These investment tax credits are amortized over
the lives of the related investments.
A
reconciliation of the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||
|
2007
|
2006
|
2005
|
||||||||
|
Statutory
rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
||||
|
State
and local taxes-net of federal benefit
|
3.9
|
5.5
|
5.2
|
|||||||
|
Tax
law change
|
0.2
|
(2.2)
|
-
|
|||||||
|
Amortization
of investment tax credit
|
(1.0)
|
(1.4)
|
(1.5)
|
|||||||
|
Adjustment
to income tax accruals
|
-
|
(2.8)
|
(2.2)
|
|||||||
|
All
other - net
|
0.4
|
0.2
|
1.2
|
|||||||
|
Effective
tax rate
|
38.5
|
%
|
34.3
|
%
|
37.7
|
%
|
||||
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 reconciliation of the total amount of unrecognized tax benefits as of
December 31, 2007:
|
(in
millions)
|
||||
|
Unrecognized
tax benefits at January 1, 2007
|
$ | 7.0 | ||
|
Gross
Increases - tax positions in prior periods
|
0.3 | |||
|
Gross
Decreases - tax positions in prior periods
|
(3.5 | ) | ||
|
Unrecognized tax
benefits at December 31, 2007
|
$ | 3.8 | ||
Of the
change in unrecognized tax benefits during 2007 of $3.2 million, $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, 2007, was $0.5 million. The remaining unrecognized tax
benefit relates to tax positions for which the ultimate deductibility is highly
certain but for which there is uncertainty about the timing of such
deductibility. Because of the impact of deferred tax accounting, other
than interest and penalties, the disallowance of the shorter deductibility
period would not affect the annual effective tax rate but would accelerate the
payment of cash to the taxing authority.
The
Company accrues interest and penalties associated with unrecognized tax benefits
in Income taxes.
During the year ended December 31, 2007, the Company recognized expense related
to interest and penalties totaling approximately $0.5 million. The
Company had approximately $0.5 million for the payment of interest and penalties
accrued as of December 31, 2007. Prior to the adoption of FIN 48,
activity related to interest and penalties was recorded at the Vectren
level.
The
liability included in Other
liabilities on the Consolidated Balance Sheet for unrecognized tax
benefits inclusive of interest, penalties and net of secondary impacts, which
are benefits, totaled $4.3 million at December 31, 2007.
From time
to time, the Company may consider changes to filed positions that could impact
its unrecognized tax benefits. However, it is not expected that such
changes would have a significant impact on earnings and would only affect the
timing of payments to taxing authorities.
Utility
Holdings does not file federal or state income tax returns separate from those
filed by its parent, Vectren Corporation. Vectren and/or certain of
its subsidiaries file income tax returns in the U.S. federal jurisdiction and
various states. The Internal Revenue Service (IRS) has conducted
examinations of the Company’s U.S. federal income tax returns for tax years
through December 31, 2004. The State of Indiana, the Company’s primary
state tax jurisdiction, has conducted examinations of state income tax returns
for tax years through December 31, 2002. On February 15, 2008, the Company
was notified by the IRS of their intent to perform a limited scope examination
of Vectren’s 2005 consolidated tax return.
|
4.
|
Transactions
with Vectren Affiliates
|
ProLiance Holdings, LLC
(ProLiance)
ProLiance,
a nonutility energy
marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas),
provides services to a broad range of municipalities, utilities, industrial
operations, schools, and healthcare institutions located throughout the Midwest
and Southeast United States. ProLiance’s customers include Vectren’s
Indiana utilities and nonutility gas supply operations as well as Citizens
Gas. ProLiance’s primary businesses include gas marketing, gas
portfolio optimization, and other portfolio and energy management
services.
Transactions
with ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2007, 2006, and 2005, totaled $602.2 million, $610.2 million, and
$908.9 million, respectively. Amounts owed to ProLiance at December
31, 2007 and 2006, for those purchases were $66.9 million and $68.2 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 2007,
compared to 72 percent in 2006 and 95 percent in 2005. Amounts
charged by ProLiance for gas supply services are established by supply
agreements with each utility.
Vectren
received regulatory approval on April 25, 2006, from the IURC for ProLiance to
provide natural gas supply services to the Company’s Indiana utilities through
March 2011. ProLiance has not provided gas supply/portfolio
administration services to VEDO since October 31, 2005.
Other Affiliate
Transactions
Vectren
has an ownership interest in Reliant Services LLC that is accounted for using
the equity method of accounting that performed facilities locating and meter
reading services for the Company. Reliant exited the meter reading
and locating businesses in 2006. For the years ended December 31,
2006, and 2005, fees for these services paid by the Company to Vectren
affiliates $7.4 million, and $7.7 million, respectively. Amounts
charged were market based. Amounts owed were less than $0.1 million
at December 31, 2006, and are included in Accounts payable to affiliated
companies in the Consolidated Balance Sheets.
|
5.
|
Borrowing
Arrangements
|
Long-Term
Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
|||||
|
(In
millions)
|
2007
|
2006
|
|||
|
UTILITY
HOLDINGS
|
|||||
|
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%
|
100.0
|
100.0
|
|||
|
Total
VUHI
|
700.0
|
700.0
|
|||
|
SIGECO
|
|||||
|
First
Mortgage Bonds
|
|||||
|
2016,
1986 Series, 8.875%
|
13.0
|
13.0
|
|||
|
2020,
1998 Pollution Control Series B, 4.50%, tax exempt
|
4.6
|
4.6
|
|||
|
2024,
2000 Environmental Improvement Series A, 4.65%, tax exempt
|
22.5
|
22.5
|
|||
|
2029,
1999 Senior Notes, 6.72%
|
80.0
|
80.0
|
|||
|
2030,
1998 Pollution Control Series B, 5.00%, tax exempt
|
22.0
|
22.0
|
|||
|
2015,
1985 Pollution Control Series A, current adjustable rate 4.00%, tax
exempt,
|
|||||
|
auction rate mode, 2007 weighted average: 3.83%
|
9.8
|
9.8
|
|||
|
2023,
1993 Environmental Improvement Series B, current adjustable rate
4.61%,
|
|||||
|
tax exempt, auction rate mode, 2007 weighted average:
4.13%
|
22.6
|
22.6
|
|||
|
2025,
1998 Pollution Control Series A, current adjustable rate 4.00%, tax
exempt,
|
|||||
|
auction rate mode, 2007 weighted average: 3.90%
|
31.5
|
31.5
|
|||
|
2030,
1998 Pollution Control Series C, current adjustable rate 4.77%, tax
exempt,
|
|||||
|
auction rate mode, 2007 weighted average: 4.15%
|
22.2
|
22.2
|
|||
|
2041,
2007 Pollution Control Series, current adjustable rate 5.22%, tax
exempt,
|
|||||
|
auction rate mode, 2007 weighted average: 4.80%
|
17.0
|
-
|
|||
|
Total
SIGECO
|
245.2
|
228.2
|
|||
|
Indiana
Gas
|
|||||
|
Senior
Unsecured Notes
|
|||||
|
2007,
Series E, 6.54%
|
-
|
6.5
|
|||
|
2013,
Series E, 6.69%
|
5.0
|
5.0
|
|||
|
2015,
Series E, 7.15%
|
5.0
|
5.0
|
|||
|
2015,
Series E, 6.69%
|
5.0
|
5.0
|
|||
|
2015,
Series E, 6.69%
|
10.0
|
10.0
|
|||
|
2025,
Series E, 6.53%
|
10.0
|
10.0
|
|||
|
2027,
Series E, 6.42%
|
5.0
|
5.0
|
|||
|
2027,
Series E, 6.68%
|
1.0
|
1.0
|
|||
|
2027,
Series F, 6.34%
|
20.0
|
20.0
|
|||
|
2028,
Series F, 6.36%
|
10.0
|
10.0
|
|||
|
2028,
Series F, 6.55%
|
20.0
|
20.0
|
|||
|
2029,
Series G, 7.08%
|
30.0
|
30.0
|
|||
|
Total
Indiana Gas
|
$ 121.0
|
$ 127.5
|
|||
|
Total
long-term debt outstanding
|
1,066.2
|
1,055.7
|
|||
|
Current
maturities of long-term debt
|
-
|
(6.5)
|
|||
|
Debt
subject to tender
|
-
|
(20.0)
|
|||
|
Unamortized
debt premium & discount - net
|
(3.6)
|
(3.9)
|
|||
|
Total
long-term debt-net
|
$
1,062.6
|
$
1,025.3
|
|||
SIGECO Pollution Control Bonds
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt has a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate will be reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation. A process to convert these notes
into another interest rate mode began in February 2008.
Utility
Holdings 2006 Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95 percent senior
unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes
were priced at par. The 2036 Notes are guaranteed by Utility
Holdings’ three public utilities: SIGECO, Indiana Gas, and
VEDO. These guarantees are full and unconditional and joint and
several. These notes, as well as the timely payment of principal and
interest, are insured by a financial guaranty insurance policy by Financial
Guaranty Insurance Company (FGIC).
The 2036
Notes have no sinking fund requirements, and interest payments are due
quarterly. The notes may be called by Utility Holdings, in whole or
in part, at any time on or after October 1, 2011, at 100 percent of principal
amount plus accrued interest. During the first and second quarters of
2006, Utility Holdings entered into several interest rate hedges with a $100
million notional amount. Upon issuance of the notes, these
instruments were settled resulting in the payment of approximately $3.3 million,
which was recorded as a Regulatory asset pursuant to
existing regulatory orders. The value paid is being amortized as an
increase to interest expense over the life of the issue.
The
proceeds from the sale of the 2036 Notes, settlement of the hedging
arrangements, and payments of issuance costs totaled approximately $92.8
million.
Utility
Holdings 2005 Issuance
In
December 2005, Utility Holdings issued senior unsecured notes with an aggregate
principal amount of $150 million in two $75 million tranches. The
first tranche was 10-year notes due December 2015, with an interest rate of 5.45
percent priced at 99.799 percent to yield 5.47 percent to maturity (2015
Notes). The second tranche was 30-year notes due December 2035 with
an interest rate of 6.10 percent priced at 99.799 percent to yield 6.11 percent
to maturity (2035 Notes).
The notes
have no sinking fund requirements, and interest payments are due
semi-annually. The notes may be called by Utility Holdings, in whole
or in part, at any time for an amount equal to accrued and unpaid interest, plus
the greater of 100 percent of the principal amount or the sum of the present
values of the remaining scheduled payments of principal and interest, discounted
to the redemption date on a semi-annual basis at the Treasury Rate, as defined
in the indenture, plus 20 basis points for the 2015 Notes and 25 basis points
for the 2035 Notes.
In
January and June 2005, Utility Holdings entered into forward starting interest
rate swaps with a total notional amount of $75 million. Upon issuance
of the debt, the instruments were settled resulting in the receipt of
approximately $1.9 million in cash, which was recorded as a regulatory liability
pursuant to existing regulatory orders. The value received is being
amortized as a reduction of interest expense over the life of the issue maturing
December 2035.
The net
proceeds from the sale of the senior notes and settlement of related hedging
arrangements approximated $150 million.
Long-Term
Debt Put & Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. The put or call provisions are not
triggered by specific events, but are based upon dates stated in the note
agreements, such as when notes are remarketed. During 2007, 2006 and
2005, no debt was put to the Company. Debt which may be put to the
Company during the years following 2007 (in millions) is zero in 2008, $80.0 in
2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. Debt
that may be put to the Company within one year is classified as Long-term debt subject to
tender in current liabilities.
Utility
Holdings, SIGECO and Indiana Gas Debt Calls
In 2006,
the Company called at par $100.0 million of Utility Holdings senior unsecured
notes originally due in 2031. In 2005, the Company called at par
$49.9 million of Indiana Gas insured senior unsecured notes originally due in
2030. The notes called in 2006 and 2005 had stated interest rates of
7.25 percent and 7.45 percent, respectively.
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax exempt auction rate mode long term debt that the Company
will convert that debt from its current auction rate mode into a daily interest
rate mode during March 2008. The debt will be subject to mandatory tender
for purchase on the conversion date at 100 percent of the principal amount plus
accrued interest.
Other
Financing Transactions
At December 31, 2005, $53.7 million of
SIGECO notes could be put to the Company in March of 2006, the date of their
next remarketing. In March of 2006, the notes were successfully
remarketed, and are now classified in Long-term
debt. Prior to
the remarketing, the notes had tax-exempt interest rates ranging from 4.75
percent to 5.00 percent. After the remarketing, interest rates are
reset every seven days using an auction process. A process
to convert these notes into another interest rate mode began in February
2008.
Other
Company debt totaling $6.5 million in 2007 was retired as
scheduled.
Future
Long-Term Debt Sinking Fund Requirements & Maturities
The
annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of
the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the
Trustee of unfunded property additions in the prescribed amount as provided in
the Mortgage Indenture. SIGECO intends to meet the 2007 sinking fund
requirement by this means and, accordingly, the sinking fund requirement for
2007 is excluded from Current
liabilities in the Consolidated Balance Sheets. At December
31, 2007, $836.7 million of SIGECO's utility plant remained unfunded under
SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance
subject to the Mortgage Indenture approximated $2.2 billion at December 31,
2007.
Consolidated
maturities of long-term debt during the five years following 2007 (in millions)
are zero in 2008, 2009, and 2010, $250.0 in 2011, and zero in 2012.
Short-Term
Borrowings
At
December 31, 2007, the Company has $520.0 million of short-term borrowing
capacity, of which approximately $134 million is available. These
borrowing arrangements expire in 2010. Credit facilities are
primarily used to support the Company’s access to the commercial paper
market. As of December 31, 2007 and 2006, commercial paper was the
only source of Short-term
borrowings. Weighted average interest rates and outstanding
balances associated with commercial paper follows.
|
Year
Ended December 31,
|
|||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
||||||||||||
|
Weighted
average commercial paper
|
|||||||||||||||
|
outstanding
during the year
|
$ | 253.6 | $ | 177.5 | $ | 193.5 | |||||||||
|
Weighted
average interest rates during the year
|
|||||||||||||||
|
Commercial
paper
|
5.54 | % | 5.16 | % | 3.42 | % | |||||||||
Covenants
Both
long-term and short-term borrowing arrangements contain customary default
provisions; restrictions on liens, sale-leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2007, the
Company was in compliance with all financial covenants.
Ratings
Triggers
None of
Utility Holdings currently outstanding debt arrangements contain ratings
triggers.
|
6.
|
Common
Shareholder’s Equity
|
During
the years ended December 31, 2007, 2006, and 2005, the Company has cumulatively
received additional capital of $45.3 million from Vectren. Of that
total, $40.0 million was funded by Vectren’s nonregulated operations, and $5.3
million was funded by new share issues from Vectren’s dividend reinvestment
plan.
Equity
Forward
As of
December 31, 2007, Vectren Corporation has access to approximately $126 million
in proceeds generated from an SEC-registered equity offering of its common
stock. Vectren executed an equity forward sale agreement (equity
forward) in connection with the offering, and therefore, did not receive
proceeds at the time of the equity offering. The equity forward
allowed Vectren to price the offering under market conditions existing at that
time. The offering proceeds, when and if received, are expected to be
contributed to Utility Holdings and used to permanently finance its
subsidiaries’ primarily electric utility capital expenditures. The
equity forward must be settled prior to February 28, 2009.
|
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 2007 and thereafter (in millions) are $0.6 in 2008, $0.2 in 2009, $0.5
in 2010, $0.1 in 2011, and zero in 2012 and thereafter. Total lease
expense (in millions) was $1.3 in 2007, $2.4 in 2006, and $3.2 in
2005.
Firm
purchase commitments for utility plant total (in millions) $36.6 in 2008, $4.0
in 2009, and zero in 2010, 2011 and 2012.
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/Climate
Change
In March
of 2005 USEPA finalized two new air emission reduction regulations. The
Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring
further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2) emissions
from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an
allowance cap and trade program requiring further reductions in mercury
emissions from coal-burning power plants. Both sets of regulations require
emission reductions in two phases. The first phase deadline for both rules
is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance
with the emission reductions required under CAIR is 2015, while the second phase
deadline for compliance with the emission reduction requirements of CAMR is
2018. However, on February 8, 2008, the US Court of Appeals for the
District of Columbia vacated the federal CAMR regulations. At this
time it is uncertain how this decision will affect Indiana’s recently finalized
CAMR implementation program.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990 and to further
comply with CAIR and CAMR of 2005, SIGECO has received authority from the IURC
to invest in clean coal technology. Using this authorization, SIGECO
invested approximately $258 million in Selective Catalytic Reduction (SCR)
systems at its coal fired generating stations. SCR technology is the most
effective method of reducing NOx emissions where high removal efficiencies are
required. To further reduce particulate matter emissions, the Company
invested approximately $49 million in a fabric filter at its largest generating
unit (287 MW). These investments were included in rate base for purposes
of determining new base rates that went into effect on August 15, 2007, (See
Note 9). Prior to being included in base rates, return on investments made
and recovery of related operating expenses were recovered through a rider
mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order, as updated with an increased spending level, allows SIGECO to recover an
approximate 8 percent return on up to $92 million, excluding AFUDC, in capital
investments through a rider mechanism which is updated every six months for
actual costs incurred. The Company may file periodic updates with the
IURC requesting modification to the spending authority. As of December 31,
2007, the Company has invested approximately $53 million in this
project. The Company expects the SO2 scrubber
will be operational in 2009. At that time, operating expenses
including depreciation expense associated with the scrubber will also be
recovered through a rider mechanism.
Once the
SO2
scrubber is operational, SIGECO’s coal fired generating fleet will be 100
percent scrubbed for SO2, 90
percent controlled for NOx, and mercury emissions will be reduced to meet the
CAMR mercury reduction standards described in the original 2005 emission
reduction regulations. The use of SCR technology positions the
Company to be in compliance with the CAIR deadlines specifying reductions in NOx
emissions by 2009 and further reductions by 2015. SIGECO's
investments in scrubber, SCR and fabric filter technology positions it to comply
with more stringent mercury reduction requirements should CAMR regulations be
further modified.
If
legislation requiring reductions in carbon dioxide and other greenhouse gases or
mandating energy from renewable sources is adopted, such regulation could
substantially affect both the costs and operating characteristics of the
Company’s fossil fuel generating plants and nonutility coal mining
operations. At this time and in the absence of final legislation,
compliance costs and other effects associated with reductions in greenhouse gas
emissions or obtaining renewable energy sources remain
uncertain.
SIGECO is
studying renewable energy alternatives, and on April 9, 2007, filed a green
power rider in order to allow customers to purchase green power and to obtain
approval of a contract to purchase 30 MW of power generated by wind
energy. The wind contract has been approved. Future
filings with the IURC with regard to new generation and/or further environmental
compliance plans will include evaluation of potential carbon
requirements.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that operated
these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded costs that it
reasonably expects to incur totaling approximately $21 million.
The
estimated accrued costs are limited to Indiana Gas’ share of the remediation
efforts. Indiana Gas has arrangements in place for 19 of the 26 sites
with other potentially responsible parties (PRP), which serve to limit Indiana
Gas’ share of response costs at these 19 sites to between 20 percent and 50
percent. With respect to insurance coverage, Indiana Gas has received
and recorded settlements from all known insurance carriers under insurance
policies in effect when these plants were in operation in an aggregate amount
approximating $20 million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has filed a declaratory judgment action against its insurance carriers seeking a
judgment finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit. While the total costs that may be incurred in connection
with addressing these sites cannot be determined at this time, SIGECO has
recorded costs that it reasonably expects to incur totaling approximately $8
million. With respect to insurance coverage, SIGECO has received and
recorded settlements from insurance carriers under insurance policies in effect
when these sites were in operation in an aggregate amount approximating the
costs it expects to incur.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had no material impact on results of operations or
financial condition since costs recorded to date approximate PRP and insurance
settlement recoveries. While the Company’s utilities have recorded
all costs which they presently expect to incur in connection with activities at
these sites, it is possible that future events may require some level of
additional remedial activities which are not presently foreseen and those costs
may not be subject to PRP or insurance recovery.
Jacobsville Superfund
Site
On July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The
USEPA has identified four sources of historic lead
contamination. These four sources shut down manufacturing operations
years ago. When drawing up the boundaries for the listing, the USEPA
included a 250 acre block of properties surrounding the Jacobsville
neighborhood, including Vectren's Wagner Operations Center. Vectren's
property has not been named as a source of the lead contamination, nor does the
USEPA's soil testing to date indicate that the Vectren property contains lead
contaminated soils. Vectren's own soil testing, completed during the
construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils. At this time, Vectren
anticipates only additional soil testing could be requested by the USEPA at some
future date.
|
9.
|
Rate
& Regulatory Matters
|
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
its Vectren North gas rate case. The order provided for a base rate
increase of $16.3 million and an ROE of 10.2 percent, with an overall rate of
return of 7.8 percent on rate base of approximately $793 million. The
settlement also provides for the recovery of $10.6 million of costs through
separate cost recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $20 million
and the treatment cannot extend beyond four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity
expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
On August
15, 2007, the Company received an order from the IURC which approved its Vectren
South electric rate case. The settlement agreement provides for an
approximate $60.8 million electric rate increase to cover the Company’s cost of
system growth, maintenance, safety and reliability. The settlement
provides for, among other things: recovery of ongoing costs and deferred costs
associated with the MISO; operations and maintenance (O&M) expense increases
related to managing the aging workforce, including the development of expanded
apprenticeship programs and the creation of defined training programs to ensure
proper knowledge transfer, safety and system stability; increased O&M
expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by Vectren’s sharing equally with
customers any profit earned above or below $10.5 million of wholesale power
margin; recovery of and return on the investment in past demand side management
programs to help encourage conservation during peak load periods; timely
recovery of the Company’s investment in certain new electric transmission
projects that benefit the MISO infrastructure; an overall rate of return of 7.32
percent on rate base of approximately $1,044 million and an allowed return on
equity (ROE) of 10.4 percent.
Vectren South (SIGECO) Gas
Base Rate Order Received
On August
1, 2007, the Company received an order from the IURC which approved its Vectren
South gas rate case. The order provided for a base rate increase of $5.1
million and an ROE of 10.15 percent, with an overall rate of return of 7.20
percent on rate base of approximately $122 million. The settlement
also provides for the recovery of $2.6 million of costs through separate cost
recovery mechanisms rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for allowance for funds
used during construction (AFUDC) and the deferral of depreciation expense after
the projects go in service but before they are included in base rates. To
qualify for this treatment, the annual expenditures are limited to $3 million
and the treatment cannot extend beyond three years on each project.
With this
order, the company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to bad debts and unaccounted for gas through the existing
gas cost adjustment mechanism, and tracking of pipeline integrity
expense.
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Case Filing
In
November 2007, the Company filed with the PUCO a request for an increase in its
base rates and charges for VEDO’s distribution business in its 17-county service
area in west central Ohio. The filing indicates that an increase in
base rates of approximately $27 million is necessary to cover the ongoing cost
of operating, maintaining and expanding the approximately 5,200-mile
distribution system used to serve 318,000 customers.
In
addition, the Company is seeking to increase the level of the monthly service
charge as well as extending the lost margin recovery mechanism currently in
place to be able to encourage customer conservation and is also seeking approval
of expanded conservation-oriented programs, such as rebate offerings on
high-efficiency natural gas appliances for existing and new home construction,
to help customers lower their natural gas bills. The Company is also
seeking approval of a multi-year bare steel and cast iron capital replacement
program.
The
Company anticipates an order from the PUCO in late 2008.
Ohio and Indiana Lost Margin
Recovery/Conservation Filings
In 2005,
the Company filed conservation programs and conservation adjustment trackers in
Indiana and Ohio designed to help customers conserve energy and reduce their
annual gas bills. The proposed programs would allow the Company to
recover costs of promoting the conservation of natural gas through conservation
trackers that work in tandem with a lost margin recovery
mechanism. These mechanisms are designed to allow the Company to
recover the distribution portion of its rates from residential and commercial
customers based on the level of customer revenues established in each utility’s
last general rate case.
Indiana
In
December 2006, the IURC approved a settlement agreement that provides for a
five-year energy efficiency program. It allows the Company’s Indiana
utilities to recover a majority of the costs of promoting the conservation of
natural gas through conservation trackers that work in tandem with a lost margin
recovery mechanism. The order was implemented in the North service
territory in December 2006, and provides for recovery of 85 percent of the
difference between weather normalized revenues actually collected by the Company
and the revenues approved in the Company’s most recent rate
case. Energy efficiency programs began in the North gas territory in
December 2006. A similar approach regarding lost margin recovery
commenced in the South gas territory on August 1, 2007, as the new base rates
went into effect, allowing for recovery of 100 percent of the difference between
weather normalized revenues collected and the revenues approved in that rate
case. The recent Vectren North base rate order also allows for full
recovery of the difference between weather normalized revenues collected by the
Company and the revenues provided for in that settlement, superseding the
original December 2006 order. While most expenses associated with
these programs are recoverable, in the first program year the Company incurred
$0.9 million in program costs without recovery, of which $0.8 million was
expensed in 2007 and, in addition contributed $0.2 million in assets that are
being depreciated over the term of the program without recovery
Ohio
In June
2007, the Public Utilities Commission of Ohio (PUCO) approved a settlement that
provides for the implementation of a lost margin recovery mechanism and a
related conservation program for the Company’s Ohio operations. This
order confirms the guidance the PUCO previously provided in a September 2006
decision. The conservation program, as outlined in the September 2006
PUCO order and as affirmed in this order, provides for a two year, $2 million
total conservation program to be paid by the Company, as well as a sales
reconciliation rider intended to be a recovery mechanism for the difference
between the weather normalized revenues actually collected by the Company and
the revenues approved by the PUCO in the Company’s most recent rate
case. Approximately 60 percent of the Company’s Ohio customers are
eligible for the conservation programs. The Ohio Consumer Counselor
(OCC) and another intervener requested a rehearing of the June 2007 order and
the PUCO granted that request in order to have additional time to consider the
merits of the request. In accordance with accounting authorization
previously provided by the PUCO, the Company began recognizing the impact of the
September 2006 order on October 1, 2006, and has recognized cumulative revenues
of $4.6 million, of which $3.3 million was recorded in 2007. The OCC
appealed the PUCO’s accounting authorization to the Ohio Supreme Court, but that
appeal has been dismissed as premature pending the PUCO’s consideration of
issues raised in the OCC’s request for rehearing. Since October 1,
2006, the Company has been ratably accruing its $2 million
commitment.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission
needs of much of the Midwest and maintains operational control over the
Company’s electric transmission facilities as well as that of other Midwest
utilities.
On April
1, 2005, the MISO energy market commenced operation (the Day 2 energy
market). As a result of being a market participant, the Company now bids
its owned generation into the Day Ahead and Real Time markets and procures power
for its retail customers at Locational Marginal Pricing (LMP) as determined by
the MISO market. The Company is typically in a net sales position with
MISO and is only occasionally in a net purchase position. Net positions
are determined on an hourly basis. When the Company is a net seller such
net revenues are included in Electric Utility revenues and
when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased
power. The Company also receives transmission revenue that
results from other members’ use of the Company’s transmission
system. These revenues are also included in Electric Utility
revenues.
Pursuant
to an order from the IURC received in December 2001, certain MISO startup costs
(referred to as Day 1 costs) were deferred, and those deferred costs are now
being recovered through base rates that went into effect on August 15,
2007. On June 1, 2005, Vectren, together with three other Indiana
electric utilities, received regulatory authority from the IURC to recover fuel
related costs and to defer other costs associated with the Day 2 energy
market. The order allows fuel related costs to be passed through to
customers in Vectren’s existing fuel cost recovery proceedings. During
2006, the IURC reaffirmed the definition of certain costs as fuel related; the
Company is following those guidelines. Other MISO fuel related and
non-fuel related administrative costs were deferred, and those deferred costs
are now being recovered through base rates that went into effect on August 15,
2007. The IURC order authorizing new base rates also provides for a
tracking mechanism associated with ongoing MISO-related costs and transmission
revenues.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a pending Day 3 market, where MISO plans to
provide bid-based regulation and contingency operating reserve markets, it is
difficult to predict near term operational impacts. MISO has
indicated that the Day 3 ancillary services market would begin in June
2008.
The need
to expend capital for improvements to the transmission system, both to SIGECO’s
facilities as well as to those facilities of adjacent utilities, over the next
several years is expected to be significant. The Company will timely
recover its investment in certain new electric transmission projects that
benefit the MISO infrastructure at a FERC approved rate of return.
Weather
Normalization
On
October 5, 2005, the IURC approved the establishment of a normal temperature
adjustment (NTA) mechanism for Vectren Energy Delivery of
Indiana. The OUCC had previously entered into a settlement agreement
with Vectren Energy Delivery of Indiana providing for the NTA. The
NTA affects the Company’s Indiana regulated residential and commercial natural
gas customers and should mitigate weather risk in those customer classes during
the October to April heating season. These Indiana customer classes
represent approximately 60-65 percent of the Company’s total natural gas heating
load.
The NTA
mechanism will mitigate volatility in distribution charges created by
fluctuations in weather by lowering customer bills when weather is colder than
normal and increasing customer bills when weather is warmer than
normal. The NTA has been applied to meters read and bills rendered
after October 15, 2005. Each subsequent monthly bill for the
seven-month heating season is adjusted using the NTA
The order
provides that the Company will make, on a monthly basis, a commitment of
$125,000 to a universal service fund program or other low-income assistance
program for the duration of the NTA or until a general rate
case. SIGECO’s portion of its commitment ceased in August 2007, and
Indiana Gas’ portion of the commitment ceased on February 14, 2008.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
VEDO Base Rate Increase in
2005
On April
13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas
distribution business. The base rate change was implemented on April
14, 2005 and provide for the recovery of some level of on-going costs to comply
with the Pipeline Safety Improvement Act of 2002.
Gas Cost Recovery (GCR)
Audit Proceedings
In 2005,
the PUCO issued an order disallowing the recovery of approximately $9.6 million
of gas costs relating to the two-year audit period ended October 2002 and in
2006, an additional $0.8 million was disallowed related to the audit period
ending October 2005. The initial audit period provided the PUCO staff its
initial review of the portfolio administration arrangement between VEDO and
ProLiance. Since November 1, 2005, the Company has used a provider other
than ProLiance for these services.
Through a
series of rehearings and appeals, including action by the Ohio Supreme Court in
the first quarter of 2007, the Company was required to refund $8.6 million to
customers. In total, the Company has reflected $6.2 million in Cost of gas sold related to
this matter, of which $1.1 million, $4.1 million, and $1.0 million were recorded
in 2007, 2005, and 2003, respectively. The impact of the disallowance
includes a sharing of the ordered refund by Vectren’s partner in
ProLiance. As of December 31, 2007, all amounts have been refunded to
customers.
|
10.
|
Derivatives
& Other Financial Instruments
|
Accounting Policy for
Derivatives
The
Company executes derivative contracts in the normal course of operations while
buying and selling commodities to be used in operations, optimizing its
generation assets, and managing risk. The Company accounts for its
derivative contracts in accordance with SFAS 133, “Accounting for Derivatives”
and its related amendments and interpretations. In most cases, SFAS
133 requires a derivative to be recorded on the balance sheet as an asset or
liability measured at its market value and that a change in the derivative's
market value be recognized currently in earnings unless specific hedge criteria
are met.
When an
energy contract that is a derivative is designated and documented as a normal
purchase or normal sale, it is exempted from mark-to-market
accounting. Otherwise, energy contracts and financial contracts that
are derivatives are recorded at market value as current or noncurrent assets or
liabilities depending on their value and on when the contracts are expected to
be settled. Contracts with counter-parties subject to master netting
arrangements are presented net in the Consolidated Balance
Sheets. The offset resulting from carrying the derivative at fair
value on the balance sheet is charged to earnings unless it qualifies as a hedge
or is subject to SFAS 71. When hedge accounting is appropriate, the
Company assesses and documents hedging relationships between the derivative
contract and underlying risks as well as its risk management objectives and
anticipated effectiveness. When the hedging relationship is highly
effective, derivatives are designated as hedges. The market value of
the effective portion of the hedge is marked to market in accumulated other
comprehensive income for cash flow hedges. Ineffective portions of
hedging arrangements are marked-to-market through earnings. For fair
value hedges, both the derivative and the underlying are marked to market
through earnings. The offset to contracts affected by SFAS 71 are
marked-to-market as a regulatory asset or liability. Market value for
derivative contracts is determined using quoted market prices from independent
sources. Following is a more detailed discussion of the Company’s use
of mark-to-market accounting in five primary areas: asset
optimization, SO2 emission
allowance risk management, natural gas procurement, and interest rate risk
management.
Asset
Optimization
Periodically,
generation capacity is in excess of that needed to serve native load and firm
wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. These
optimization strategies involve the sale of excess generation into the MISO day
ahead and real-time markets. As part of these strategies, the Company
may execute energy contracts that are integrated with portfolio requirements
around power supply and delivery and are short-term purchase and sale
transactions that expose the Company to limited market risk. Asset
optimization contracts that are derivatives are recorded at market
value.
At December 31, 2007 and
2006, no asset optimization derivative contracts were outstanding. The proceeds
received and paid upon settlement of both purchase and sale contracts along with
changes in market value of open contracts that are derivatives
are recorded in Electric Utility
Revenues. Net revenues from asset optimization activities
totaled $39.8 million in 2007, $29.8 million in 2006 and $38.0 million in
2005.
SO2
Emission Allowance Risk Management
The
Company’s wholesale power marketing operations are exposed to price risk
associated with SO2 emission
allowances. To mitigate this risk, the Company executed call options
to hedge wholesale emission allowance utilization in future
periods. The Company designated and documented these derivatives as
cash flow hedges. At December 31, 2007, a deferred gain of
approximately $0.7 million remains in accumulated comprehensive income related
to these call options which will be recognized in earnings as emission
allowances are utilized. Hedge ineffectiveness totaled $0.2 million
of expense in 2006 and $0.8 million of expense in 2005. No SO2 emission
allowance hedges are outstanding as of December 31, 2007.
Natural
Gas Procurement Activity
The
Company’s regulated operations have limited exposure to commodity price risk for
purchases and sales of natural gas and electricity for retail customers due to
current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms. Although Vectren’s regulated operations
are exposed to limited commodity price risk, volatile natural gas prices can
result in higher working capital requirements, increased expenses including
unrecoverable interest costs, uncollectible accounts expense, and unaccounted
for gas, and some level of price- sensitive reduction in volumes
sold. The Company may mitigate these risks by using derivative
contracts. These contracts are subject to regulation which allows for
reasonable and prudent hedging costs to be recovered through
rates. When regulation is involved, SFAS 71 controls when the offset
to mark-to-market accounting is recognized in earnings.
At
December 31, 2007 and 2006, 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.
Interest
rate swaps hedging the fair value of a planned VUHI debt issuance in 2008 with a
total notional amount of $80.0 million are outstanding. The fair
value liability associated with those swaps was $8.9 million at December 31,
2007. Related to derivative instruments associated with completed
debts issuances, an approximate $2.2 million net regulatory liability remains at
December 31, 2007. Of that net liability, $0.6 million will be
reclassified to earnings in 2008, $0.6 million was reclassified to earnings in
2007, and $0.7 million was reclassified to earnings during 2006.
Fair Value of Other
Financial Instruments
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
||||||||||||||||
|
2007
|
2006
|
|||||||||||||||
|
(In
millions)
|
Carrying
Amount
|
Est.
Fair
Value
|
In
millions
|
Est.
Fair
Value
|
||||||||||||
|
Long-term
debt
|
$ | 1,066.2 | $ | 1,049.2 | $ | 1,055.7 | $ | 1,072.6 | ||||||||
|
Short-term
borrowings
|
385.9 | 385.9 | 270.1 | 270.1 | ||||||||||||
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 asset optimization 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 marketing
operations. In total, regulated operations supply natural gas and /or
electricity to over one million customers. In total, the Company has
three operating segments as defined by SFAS 131 “Disclosure About Segments of an
Enterprise and Related Information” (SFAS 131). Net income is the
measure of profitability used by management for all
operations. Information related to the Company’s business segments is
summarized below:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Revenues
|
||||||||||||
|
Gas
Utility Services
|
$ | 1,269.4 | $ | 1,232.5 | $ | 1,359.7 | ||||||
|
Electric
Utility Services
|
487.9 | 422.2 | 421.4 | |||||||||
|
Other
Operations
|
40.4 | 36.6 | 36.1 | |||||||||
|
Eliminations
|
(38.7 | ) | (34.8 | ) | (35.4 | ) | ||||||
|
Total
revenues
|
$ | 1,759.0 | $ | 1,656.5 | $ | 1,781.8 | ||||||
|
Profitability
Measure - Net Income
|
||||||||||||
|
Gas
Utility Services
|
$ | 41.7 | $ | 41.5 | $ | 34.7 | ||||||
|
Electric
Utility Services
|
52.6 | 41.6 | 50.4 | |||||||||
|
Other
Operations
|
12.2 | 8.3 | 10.0 | |||||||||
|
Total
net income
|
$ | 106.5 | $ | 91.4 | $ | 95.1 | ||||||
|
Amounts
Included in Profitability Measures
|
||||||||||||
|
Depreciation
& Amortization
|
||||||||||||
|
Gas
Utility Services
|
$ | 70.6 | $ | 67.6 | $ | 64.9 | ||||||
|
Electric
Utility Services
|
66.0 | 61.8 | 56.9 | |||||||||
|
Other
Operations
|
21.8 | 21.9 | 19.5 | |||||||||
|
Total
depreciation & amortization
|
$ | 158.4 | $ | 151.3 | $ | 141.3 | ||||||
|
Interest
Expense
|
||||||||||||
|
Gas
Utility Services
|
$ | 39.8 | $ | 40.7 | $ | 40.2 | ||||||
|
Electric
Utility Services
|
29.6 | 28.6 | 23.7 | |||||||||
|
Other
Operations
|
11.2 | 8.2 | 6.0 | |||||||||
|
Total
interest expense
|
$ | 80.6 | $ | 77.5 | $ | 69.9 | ||||||
|
Income
Taxes
|
||||||||||||
|
Gas
Utility Services
|
$ | 33.2 | $ | 22.6 | $ | 22.3 | ||||||
|
Electric
Utility Services
|
38.0 | 25.3 | 33.5 | |||||||||
|
Other
Operations
|
(4.5 | ) | (0.2 | ) | 1.7 | |||||||
|
Total
income taxes
|
$ | 66.7 | $ | 47.7 | $ | 57.5 | ||||||
|
Capital
Expenditures
|
||||||||||||
|
Gas
Utility Services
|
$ | 128.9 | $ | 76.8 | $ | 81.0 | ||||||
|
Electric
Utility Services
|
134.7 | 156.8 | 100.0 | |||||||||
|
Other Operations
|
36.4 | 24.8 | 29.9 | |||||||||
|
Non-cash costs
& changes in accruals
|
2.5 | (8.4 | ) | 6.9 | ||||||||
|
Total
capital expenditures
|
$ | 302.5 | $ | 250.0 | $ | 217.8 | ||||||
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Assets
|
||||||||
|
Utility
Group
|
||||||||
|
Gas
Utility Services
|
$ | 2,049.1 | $ | 1,953.6 | ||||
|
Electric
Utility Services
|
1,369.2 | 1,277.6 | ||||||
|
Other
Operations
|
245.7 | 225.9 | ||||||
|
Eliminations
|
(20.3 | ) | (16.3 | ) | ||||
|
Total
assets
|
$ | 3,643.7 | $ | 3,440.8 | ||||
|
12.
|
Additional
Operational & Balance Sheet
Information
|
Prepayments and other current
assets in the Consolidated Balance Sheets consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Prepaid
gas delivery service
|
$ | 65.2 | $ | 66.2 | ||||
|
Prepaid
taxes
|
13.6 | 20.7 | ||||||
|
Deferred
income taxes
|
- | 3.5 | ||||||
|
Other
prepayments & current assets
|
14.5 | 12.8 | ||||||
|
Total
prepayments & other current assets
|
$ | 93.3 | $ | 103.2 | ||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2007
|
2006
|
||||||
|
Refunds
to customers & customer deposits
|
$ | 41.2 | $ | 42.3 | ||||
|
Accrued
taxes
|
32.5 | 28.3 | ||||||
|
Accrued
interest
|
16.1 | 15.5 | ||||||
|
Deferred
income taxes
|
4.9 | - | ||||||
|
Asset
retirement obligation
|
9.5 | - | ||||||
|
Accrued
salaries & other
|
34.7 | 29.7 | ||||||
|
Total
accrued liabilities
|
$ | 138.9 | $ | 115.8 | ||||
Other – net in the
Consolidated Statements of Income consists of the following:
|
Year
Ended December 31,
|
|||||||||||||||
|
(In
millions)
|
2007
|
2006
|
2005
|
||||||||||||
|
AFUDC
& capitalized interest
|
$ | 5.3 | $ | 4.8 | $ | 2.5 | |||||||||
|
Interest
income
|
2.3 | 0.7 | 0.6 | ||||||||||||
|
Other
income
|
1.8 | 2.1 | 2.8 | ||||||||||||
|
Total
other – net
|
$ | 9.4 | $ | 7.6 | $ | 5.9 | |||||||||
|
13.
|
Impact
of Recently Issued Accounting
Guidance
|
SFAS No.
157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
157). SFAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles (GAAP), and
expands disclosures about fair value measurements. This statement
does not require any new fair value measurements; however, the standard will
impact how other fair value based GAAP is applied. SFAS 157 is
effective for financial statements issued for fiscal years beginning after
November 15, 2007. However, in December 2007, the FASB issued
proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). This proposed FSP partially defers the
effective date of Statement 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of this FSP. The Company will adopt SFAS 157 on January 1, 2008,
except as it applies to those nonfinancial assets and nonfinancial liabilities
as noted in proposed FSP FAS 157-b. The partial adoption of SFAS 157
will not have a material impact on the Company’s financial position, results of
operations or cash flows.
SFAS 159
In
February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115" (SFAS 159). SFAS 159 permits entities to measure
many financial instruments and certain other items at fair
value. Items eligible for the fair value measurement option include:
financial assets and financial liabilities with certain exceptions; firm
commitments that would otherwise not be recognized at inception and that involve
only financial instruments; nonfinancial insurance contracts and warranties that
the insurer can settle by paying a third party to provide those goods or
services; and host financial instruments resulting from separation of an
embedded financial derivative instrument from a nonfinancial hybrid
instrument. The fair value option may be applied instrument by
instrument, with few exceptions, is an irrevocable election and is applied only
to entire instruments. SFAS 159 is effective as of the beginning of
an entity’s first fiscal year that begins after November 15,
2007. The Company will adopt SFAS 159 on January 1, 2008, and does
not expect that adoption will have a material impact this statement will have on
its financial statements and results of operations.
SFAS 141 (Revised
2007)
In
December 2007, the FASB issued SFAS 141, "Business Combinations" (SFAS
141). SFAS 141 establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any Noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141 applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. SFAS 141 applies prospectively to
business combinations with an acquisition date on or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. Early adoption is not permitted. The Company will adopt
SFAS 141 on January 1, 2009, and because the provisions of this standard are
applied prospectively, the impact to the Company cannot be determined until the
transactions occur.
SFAS 160
In
December 2007, the FASB issued SFAS 160, "Noncontrolling Interests in
Consolidated Financial Statements-an Amendment of ARB No. 51" (SFAS
160). SFAS 160 establishes accounting and reporting standards that
require that the ownership percentages in subsidiaries held by parties other
than the parent be clearly identified, labeled, and presented separately from
the parent’s equity in the equity section of the consolidated balance sheet; the
amount of consolidated net income attributable to the parent and the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement; that changes in the parents ownership
interest while it retains control over its subsidiary be accounted for
consistently; that when a subsidiary is deconsolidated, any retained
noncontrolling equity investment be initially measured at fair value; and that
sufficient disclosure is made to clearly identify and distinguish between the
interests of the parent and the noncontrolling owners. SFAS 160
applies to all entities that prepare consolidated financial statements, except
for non-profit entities. SFAS 160 is effective for fiscal years
beginning after December 31, 2008. Early adoption is not
permitted. The Company will adopt SFAS 160 on January 1, 2009, and is
currently assessing the impact this statement will have on its financial
statements and results of operations.
|
14.
|
Subsidiary
Guarantor and Consolidating
Information
|
The
Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of Utility Holdings’ $520 million in short-term credit facilities, of
which $386 million is outstanding at December 31, 2007, and Utility Holdings’
$700.0 million unsecured senior notes outstanding at December 31,
2007. 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, 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 Income for the year ended December 31, 2005 (in
millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,355.6 | $ | - | $ | - | $ | 1,359.7 | ||||||||
|
Electric
utility
|
421.4 | - | - | 421.4 | ||||||||||||
| Other | - | 36.1 | (35.4 | ) | 0.7 | |||||||||||
|
Total
operating revenues
|
1,777.0 | 36.1 | (35.4 | ) | 1,781.8 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
973.3 | - | - | 973.3 | ||||||||||||
|
Cost
of fuel & purchased power
|
144.1 | - | - | 144.1 | ||||||||||||
|
Other
operating
|
274.4 | 0.1 | (33.2 | ) | 241.3 | |||||||||||
|
Depreciation
& amortization
|
121.7 | 19.3 | 0.3 | 141.3 | ||||||||||||
|
Taxes
other than income taxes
|
64.7 | 0.4 | 0.1 | 65.2 | ||||||||||||
|
Total
operating expenses
|
1,578.2 | 19.8 | (32.8 | ) | 1,565.2 | |||||||||||
|
OPERATING
INCOME
|
198.8 | 16.3 | (2.6 | ) | 216.6 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 81.2 | (81.2 | ) | - | |||||||||||
|
Other
– net
|
4.3 | 37.8 | (36.2 | ) | 5.9 | |||||||||||
|
Total
other income (expense)
|
4.3 | 119.0 | (117.4 | ) | 5.9 | |||||||||||
|
Interest
expense
|
64.4 | 42.9 | (37.4 | ) | 69.9 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
138.7 | 92.4 | (82.6 | ) | 152.6 | |||||||||||
|
Income
taxes
|
57.5 | 1.4 | (1.4 | ) | 57.5 | |||||||||||
|
NET
INCOME
|
$ | 81.2 | $ | 91.0 | $ | (81.2 | ) | $ | 95.1 | |||||||
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
Statement of Cash Flows for the year ended December 31, 2005 (in
millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 224.0 | $ | 41.8 | $ | - | $ | 265.8 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Long-term
debt - net of issuance costs & hedging proceeds
|
- | 150.0 | - | 150.0 | ||||||||||||
|
Additional
capital contribution
|
125.0 | 20.0 | (125.0 | ) | 20.0 | |||||||||||
|
Requirements
for:
|
||||||||||||||||
|
Dividends
to parent
|
(80.7 | ) | (80.7 | ) | 80.7 | (80.7 | ) | |||||||||
|
Retirement
of long-term debt, including premiums paid
|
(49.9 | ) | - | - | (49.9 | ) | ||||||||||
|
Redemption
of preferred stock of subsidiary
|
(0.1 | ) | - | - | (0.1 | ) | ||||||||||
|
Net change in short-term borrowings, including from other
|
||||||||||||||||
|
Vectren
companies
|
(24.6 | ) | (81.1 | ) | 24.3 | (81.4 | ) | |||||||||
|
Net
cash flows from financing activities
|
(30.3 | ) | 8.2 | (20.0 | ) | (42.1 | ) | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from:
|
||||||||||||||||
|
Consolidated subsidiary distributions
|
- | 80.7 | (80.7 | ) | - | |||||||||||
|
Other investing activities
|
0.1 | - | - | 0.1 | ||||||||||||
|
Requirements
for:
|
||||||||||||||||
|
Capital expenditures, excluding AFUDC equity
|
(187.5 | ) | (30.3 | ) | - | (217.8 | ) | |||||||||
|
Consolidated subsidiary investments
|
- | (125.0 | ) | 125.0 | - | |||||||||||
|
Net change in notes receivable from other Vectren
companies
|
- | 24.3 | (24.3 | ) | - | |||||||||||
|
Net
cash flows from investing activities
|
(187.4 | ) | (50.3 | ) | 20.0 | (217.7 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
6.3 | (0.3 | ) | - | 6.0 | |||||||||||
|
Cash
& cash equivalents at beginning of period
|
4.7 | 1.0 | - | 5.7 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 11.0 | $ | 0.7 | $ | - | $ | 11.7 | ||||||||
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 | |||||||
Consolidating
Balance Sheet as of December 31, 2006 (in millions):
|
ASSETS
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Assets
|
||||||||||||||||
|
Cash
& cash equivalents
|
$ | 5.7 | $ | 22.8 | $ | - | $ | 28.5 | ||||||||
|
Accounts
receivable - less reserves
|
134.8 | - | - | 134.8 | ||||||||||||
|
Receivables
due from other Vectren companies
|
6.1 | 146.0 | (151.8 | ) | 0.3 | |||||||||||
|
Accrued
unbilled revenues
|
121.4 | - | - | 121.4 | ||||||||||||
|
Inventories
|
139.6 | 2.3 | - | 141.9 | ||||||||||||
|
Recoverable
fuel & natural gas costs
|
1.8 | - | - | 1.8 | ||||||||||||
|
Prepayments
& other current assets
|
91.2 | 14.7 | (2.7 | ) | 103.2 | |||||||||||
|
Total
current assets
|
500.6 | 185.8 | (154.5 | ) | 531.9 | |||||||||||
|
Utility
Plant
|
||||||||||||||||
|
Original
cost
|
3,820.2 | - | - | 3,820.2 | ||||||||||||
|
Less: accumulated
depreciation & amortization
|
1,434.7 | - | - | 1,434.7 | ||||||||||||
|
Net
utility plant
|
2,385.5 | - | - | 2,385.5 | ||||||||||||
|
Investments
in consolidated subsidiaries
|
- | 1,129.7 | (1,129.7 | ) | - | |||||||||||
|
Notes
receivable from consolidated subsidiaries
|
- | 575.3 | (575.3 | ) | - | |||||||||||
|
Investments
in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other
investments
|
15.4 | 6.0 | - | 21.4 | ||||||||||||
|
Nonutility
property - net
|
5.2 | 157.9 | - | 163.1 | ||||||||||||
|
Goodwill
- net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory
assets
|
103.3 | 13.5 | - | 116.8 | ||||||||||||
|
Other
assets
|
16.1 | 0.8 | - | 16.9 | ||||||||||||
|
TOTAL
ASSETS
|
$ | 3,231.3 | $ | 2,069.0 | $ | (1,859.5 | ) | $ | 3,440.8 | |||||||
|
LIABILITIES &
SHAREHOLDER'S EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Liabilities
|
||||||||||||||||
|
Accounts
payable
|
$ | 131.5 | $ | 4.7 | $ | - | $ | 136.2 | ||||||||
|
Accounts
payable to affiliated companies
|
68.1 | 0.1 | - | 68.2 | ||||||||||||
|
Payables
to other Vectren companies
|
44.0 | 0.1 | (18.8 | ) | 25.3 | |||||||||||
|
Refundable
fuel & natural gas costs
|
35.3 | - | - | 35.3 | ||||||||||||
|
Accrued
liabilities
|
107.3 | 11.2 | (2.7 | ) | 115.8 | |||||||||||
|
Short-term
borrowings
|
- | 270.1 | - | 270.1 | ||||||||||||
|
Short-term
borrowings from
|
||||||||||||||||
|
other
Vectren companies
|
133.0 | - | (133.0 | ) | - | |||||||||||
|
Current
maturities of long-term debt
|
6.5 | - | - | 6.5 | ||||||||||||
|
Long-term
debt subject to tender
|
20.0 | - | - | 20.0 | ||||||||||||
|
Total
current liabilities
|
545.7 | 286.2 | (154.5 | ) | 677.4 | |||||||||||
|
Long-Term
Debt
|
||||||||||||||||
|
Long-term
debt - net of current maturities &
|
||||||||||||||||
|
debt
subject to tender
|
327.3 | 698.0 | - | 1,025.3 | ||||||||||||
|
Long-term
debt due to VUHI
|
575.3 | - | (575.3 | ) | - | |||||||||||
|
Total
long-term debt - net
|
902.6 | 698.0 | (575.3 | ) | 1,025.3 | |||||||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred
income taxes
|
265.9 | 16.3 | - | 282.2 | ||||||||||||
|
Regulatory
liabilities
|
285.0 | 6.1 | - | 291.1 | ||||||||||||
|
Deferred
credits & other liabilities
|
102.4 | 5.7 | - | 108.1 | ||||||||||||
|
Total
deferred credits & other liabilities
|
653.3 | 28.1 | - | 681.4 | ||||||||||||
|
Common
Shareholder's Equity
|
||||||||||||||||
|
Common
stock (no par value)
|
776.3 | 632.9 | (776.3 | ) | 632.9 | |||||||||||
|
Retained
earnings
|
352.5 | 422.9 | (352.5 | ) | 422.9 | |||||||||||
|
Accumulated
other comprehensive income
|
0.9 | 0.9 | (0.9 | ) | 0.9 | |||||||||||
|
Total
common shareholder's equity
|
1,129.7 | 1,056.7 | (1,129.7 | ) | 1,056.7 | |||||||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,231.3 | $ | 2,069.0 | $ | (1,859.5 | ) | $ | 3,440.8 | |||||||
|
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 2007 and 2006
follows:
|
(In
millions)
|
Q1
|
Q2
|
Q3
|
Q4
|
||||||||||||
|
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 | ||||||||||||
|
2006
|
||||||||||||||||
|
Results
of Operations:
|
||||||||||||||||
|
Operating
revenues
|
$ | 678.3 | $ | 159.1 | $ | 240.5 | $ | 578.6 | ||||||||
|
Operating
income
|
89.7 | 27.3 | 23.7 | 68.3 | ||||||||||||
|
Net
income
|
43.4 | 7.1 | 6.5 | 34.4 | ||||||||||||
ITEM
9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM
9A(T). CONTROLS AND PROCEDURES
Changes in Internal Controls
over Financial Reporting
During
the quarter ended December 31, 2007, there have been no changes to the Company’s
internal controls over financial reporting that have materially affected, or are
reasonably likely to materially affect, the Company’s internal control over
financial reporting.
Conclusion Regarding the
Effectiveness of Disclosure Controls and Procedures
As of
December 31, 2007, the Company conducted an evaluation under the supervision and
with the participation of the Chief Executive Officer and Chief Financial
Officer of the effectiveness and the design and operation of the Company's
disclosure controls and procedures. Based on that evaluation, the
Chief Executive Officer and the Chief Financial Officer have concluded that the
Company's disclosure controls and procedures are effective as of December 31,
2007, to ensure that information required to be disclosed in reports filed or
submitted under the Exchange Act is:
|
1)
|
recorded,
processed, summarized and reported within the time periods specified in
the SEC’s rules and forms, and
|
|
2)
|
accumulated
and communicated to management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
|
Management’s Report on
Internal Control over Financial Reporting
Utility
Holdings’ management is responsible for establishing and maintaining adequate
internal control over financial reporting. Under the supervision and
with the participation of management, including the Chief Executive Officer and
Chief Financial Officer, the Company conducted an evaluation of the
effectiveness of its internal control over financial reporting based on the
framework in Internal Control
- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on that evaluation
under the framework in Internal Control — Integrated
Framework, the Company concluded that its internal control over financial
reporting was effective as of December 31, 2007.
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. The Company intends to
disclose any amendments to the Code of Ethics or waivers of the Code of Ethics
on behalf of the Company’s directors or officers including, but not limited to,
the principal executive officer, principal financial officer, principal
accounting officer or controller and persons performing similar functions on the
Company’s website at the internet address set forth above promptly following the
date of such amendment or waiver and such information will also be available by
mail upon request to the address listed above.
ITEM
11. EXECUTIVE COMPENSATION
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, 2007 and
2006. The fees presented below represent total Vectren fees, the
majority of which are allocated to Utility Holdings.
|
2007
|
2006
|
|||||||
|
Audit
Fees(1)
|
$ | 1,157,989 | $ | 1,514,008 | ||||
|
Audit-Related
Fees(2)
|
258,795 | 73,250 | ||||||
|
Tax
Fees(3)
|
242,219 | 151,026 | ||||||
|
Total
Fees Paid to Deloitte(4)
|
$ | 1,659,003 | $ | 1,738,284 | ||||
|
(1)
|
Aggregate
fees incurred and payable to Deloitte for professional services rendered
for the audits of Vectren’s and Utility Holdings’ 2007 and 2006
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
2007 and 2006 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 $83,989 and $91,008 in 2007 and 2006,
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 $20,426 and $13,971 in 2007
and 2006, 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, 2007, 2006, and 2005, the Company’s Schedule II --
Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is
presented herein. The report of Deloitte & Touche LLP on the
schedule may be found in Item 8. All other schedules are omitted as
the required information is inapplicable or the information is presented in the
Consolidated Financial Statements or related notes in Item 8.
SCHEDULE
II
Vectren
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
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 | ||||||||||
|
Year
2005 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 1.9 | $ | 14.4 | $ | - | $ | 13.7 | $ | 2.6 | ||||||||||
|
OTHER
RESERVES:
|
||||||||||||||||||||
|
Year
2007 – Restructuring costs
|
$ | 1.7 | $ | - | $ | - | $ | 1.1 | $ | 0.6 | ||||||||||
|
Year
2006 – Restructuring costs
|
$ | 2.4 | $ | - | $ | - | $ | 0.7 | $ | 1.7 | ||||||||||
|
Year
2005 – Restructuring costs
|
$ | 2.7 | $ | - | $ | - | $ | 0.3 | $ | 2.4 | ||||||||||
List of
Exhibits
The
Company has incorporated by reference herein certain exhibits as specified below
pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the
Company attached to this filing filed electronically with the SEC are listed
below. Exhibits for the Company are listed in the Index to Exhibits
beginning on page 76.
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
|
Ratio
of Earnings to Fixed Charges
|
|
21
|
List
of Company’s Significant Subsidiaries
|
|
23
|
Consent
of Independent Registered Public Accounting Firm
|
INDEX
TO EXHIBITS
2. Plan
of Acquisition, Reorganization, Arrangement, Liquidation or
Succession
|
2.1
|
Asset
Purchase Agreement dated December 14, 1999 between Indiana Energy, Inc.
and The Dayton Power and Light Company and Number-3CHK with a commitment
letter for a 364-Day Credit Facility dated December 16,
1999. (Filed and designated in Current Report on Form 8-K dated
December 28, 1999, File No. 1-9091, as Exhibit 2 and
99.1)
|
3. Articles of
Incorporation and By-Laws
|
3.1
|
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)
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|
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.)
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|
4.3
|
Indenture
dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association.
(Filed and designated in Form 8-K, dated October 19, 2001, File No.
1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19,
2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery of
Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental
Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery
of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit
4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated November 18,
2005, File No. 1-16739, as Exhibit 4.1). Form of Fifth
Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas & Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Incorporated
by reference to Exhibit 4.1 to the Current Report on Form 8-K, dated
October 16, 2006, File No.
1-16739).
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|
4.4
|
Note
purchase agreement, dated October 11, 2005, between Vectren Capital Corp.
and each of the purchasers named therein. (Filed designated in
Form 10-K for the year ended December 31, 2005, File No. 1-15467, as
Exhibit 4.4.)
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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.).
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|
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.)
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|
10.3
|
Indiana
Energy, Inc. Unfunded Supplemental Retirement Plan for a Select Group of
Management Employees as amended and restated effective December 1,
1998. (Filed and designated in Form 10-Q for the quarterly
period ended December 31, 1998, File No. 1-9091, as Exhibit
10-G.)
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|
10.4
|
Vectren
Corporation At Risk Compensation Plan effective May 1, 2001,(as amended
and restated s of May 1, 2006). (Filed and designated in
Vectren Corporation’s Proxy Statement dated March 15, 2006, File No.
1-15467, as Appendix H.)
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|
10.5
|
Vectren
Corporation Non-Qualified Deferred Compensation Plan, as amended and
restated effective January 1, 2001. (Filed and designated in
Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as
Exhibit 10.32.)
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|
10.6
|
Vectren
Corporation Change in Control Agreement between Vectren Corporation and
Niel C. Ellerbrook dated as of March 1, 2005. (Filed and
designated in Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit
99.1.)
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|
10.7
|
Vectren
Corporation At Risk Compensation Plan specimen Restricted Stock Grant
Agreement for officers, effective January 1, 2005. (Filed and
designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as
Exhibit 99.1.)
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|
10.8
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock grant
agreement for officers, effective January 1, 2006. (Filed and
designated in Form 8-K, dated February 27, 2006, File No. 1-15467, as
Exhibit 99.1.)
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|
10.9
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock grant
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.1.)
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|
10.10
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock units
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.2.)
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|
10.11
|
Vectren
Corporation At Risk Compensation Plan specimen Stock Option Grant
Agreement for officers, effective January 1, 2005. (Filed and
designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as
Exhibit 99.2.)
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|
10.12
|
Vectren
Corporation specimen employment agreement dated February 1,
2005. (Filed and designated in Form 8-K, dated February 1,
2005, File No. 1-15467, as Exhibit
99.1.)
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|
10.13
|
Life
Insurance Replacement Agreement between Vectren Corporation and certain
named officers, effective December 31, 2006. (Filed and
designated in Form 8-K, dated December 31, 2006, File No. 1-15467 as
Exhibit 99.1.)
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|
10.14
|
Gas
Sales and Portfolio Administration Agreement between Indiana Gas Company,
Inc. and ProLiance Energy, LLC, effective August 30,
2003. (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No. 1-15467, as Exhibit
10.15.)
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|
10.15
|
Gas
Sales and Portfolio Administration Agreement between Southern Indiana Gas
and Electric Company and ProLiance Energy, LLC, effective September 1,
2002. (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No. 1-15467, as Exhibit
10.16.)
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|
10.16
|
Formation
Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC
Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke
Utility, Citizens Energy Services Corporation and ProLiance Energy, LLC,
effective March 15, 1996. (Filed and designated in Form 10-Q
for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit
10-C.)
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|
10.17
|
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among Vectren
Utility Holdings, Inc., and each of the purchasers named
therein. (Filed and designated in Form 10-K, for the year ended
December 31, 2005, File No. 1-15467, as Exhibit
10.24.)
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|
10.18
|
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among Vectren
Capital Corp., and each of the purchasers named therein. (Filed
and designated in Form 10-K, for the year ended December 31, 2005, File
No. 1-15467, as Exhibit 10.25.)
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12.
Ratio of Earnings to Fixed Charges
The
Company’s Ratio of Earnings to Fixed Charges is attached hereto as Exhibit 12
(Filed herewith.)
21.
Subsidiaries of the Company
The list
of the Company's significant subsidiaries is attached hereto as Exhibit 21 (Filed
herewith.)
23.
Consents of Experts and Counsel
The
consent of Deloitte & Touche LLP is attached hereto as Exhibit
23 (Filed herewith.)
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31.
Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of
2002
|
|
Chief
Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1 (Filed
herewith.)
|
|
Chief
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed
herewith.)
|
|
32.
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
Certification
Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as
Exhibit 32 (Filed herewith.)
99.
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.)
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|
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.)
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|
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.)
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SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
VECTREN
UTILITY HOLDINGS, INC.
Dated
February 28,
2008 /s/ Niel C.
Ellerbrook
Niel C.
Ellerbrook,
Chairman,
Chief Executive Officer and Director
Pursuant
to the requirements of the Securities and Exchange Act of 1934, this report has
been signed below by the following persons on behalf of the Registrant and in
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||
|
/s/
Niel C. Ellerbrook
|
Chairman,
Chief Executive Officer, and Director
|
February
28, 2008
|
||
|
Niel
C. Ellerbrook
|
(Principal
Executive Officer)
|
|||
|
/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President and Chief Financial Officer
|
February
28, 2008
|
||
|
Jerome
A. Benkert, Jr.
|
(Principal
Financial Officer)
|
|||
|
/s/ M.
Susan Hardwick
|
Vice
President, Controller and Assistant Treasurer
|
February
28, 2008
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
|
/s/
Ronald E. Christian
|
Director
|
February
28, 2008
|
||
|
Ronald
E. Christian
|
||||
|
/s/
William S. Doty
|
Director
|
February
28, 2008
|
||
|
William
S. Doty
|