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, 2006
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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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
o.
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, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filer □ Accelerated
filer □ Non-accelerated
filer ý
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes □
No
ý
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, 2006, 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, 2007
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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.
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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4
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8
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11
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11
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12
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12
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Part
II
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13
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14
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14
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Quantitative
and Qualitative Disclosures About Market
Risk
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32
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|||||
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34
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68
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68
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68
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Part
III
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68
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68
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68
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68
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69
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Part
IV
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70
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75
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| (A) |
-
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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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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PART
I
ITEM
1. BUSINESS
Description
of the Business
Vectren
Utility Holdings, Inc. (Utility Holdings or the Company), 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), Southern Indiana Gas and Electric
Company (SIGECO), and the Ohio operations. Utility Holdings also has assets
that
provide information technology and other services to the utilities.
Indiana
Gas provides energy delivery services to approximately 565,000 natural gas
customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 141,000 electric customers and approximately
112,000 natural 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, (53% ownership) and Indiana Gas (47% ownership). The
Ohio operations generally do business as Vectren Energy Delivery of Ohio.
Vectren,
an Indiana corporation, is an energy holding company headquartered in
Evansville, Indiana, and organized on June 10, 1999. Both Vectren and Utility
Holdings were exempt from registration pursuant to Section 3(a) (1) and 3(c)
of
the Public Utility Holding Company Act of 1935, which was repealed effective
February 8, 2006 by the Energy Policy Act of 2005 (Energy Act). Both Vectren
and
Utility Holdings are holding companies as defined by the Energy Act.
Narrative
Description of the Business
The
Company segregates its businesses into three operating segments: Gas Utility
Services, Electric Utility Services, and Other Operations. 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 marketing operations. The Company
collectively refers to its gas and electric operating segments as its regulated
operations. In total, these regulated operations supply natural gas and/or
electricity to over one million customers. Other Operations primarily provide
information technology and other support services to those utility operations.
At
December 31, 2006, the Company had $3.4 billion in total assets, with $2.0
billion (57%) attributed to the Gas Utility Services, $1.3 billion (37%)
attributed to the Electric Utility Services, and $0.2 billion (6%) attributed
to
Other Operations. Net income for the year ended December 31, 2006, was $91.4
million with $83.1 million attributed to regulated operations and $8.3 million
attributed to other operations. Net income for the year ended 2005 was $95.1
million.
For
further information, refer to Note 12 regarding the activities and assets of
the
Company’s operating segments 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, 2006, the Company supplied natural gas service to approximately
995,000 Indiana and Ohio customers, including 909,000 residential, 84,000
commercial, and 2,000 industrial and other contract customers. This represents
customer base growth of 0.3% compared to 2005.
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, Muncie, Anderson, Lafayette, West Lafayette, Bloomington,
Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and
Richmond, and suburban areas surrounding Indianapolis. The largest community
served outside of Indiana is Dayton, Ohio.
Revenues
For
the
year ended December 31, 2006, gas utility revenues were approximately $1,232.5
million, of which residential customers accounted for 66%, commercial 28%,
and
industrial and other contract customers 6%.
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 182.6 MMDth for the year ended December 31, 2006.
Gas transported or sold to residential and commercial customers was 97.7 MMDth
representing 53% of throughput. Gas transported or sold to industrial and other
contract customers was 84.9 MMDth representing 47% of throughput. Rates for
transporting gas generally provide for the same margins earned by selling gas
under applicable sales tariffs.
The
sale
of gas is seasonal and strongly 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 Energy, 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. In addition, the Company prepays ProLiance
for natural gas delivery services during the seven months prior to the peak
heating season. The volume of gas per day that can be delivered during peak
demand periods for each utility is located in “Item 2 Properties.”
Gas
Purchases
In
2006,
the Company purchased 95,561 MDth volumes of gas at an average cost of $8.64
per
Dth, of which approximately 72% was purchased from ProLiance and 28% was
purchased from other 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
the 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 $8.64 in 2006; $9.05 in 2005; $6.92 in 2004; $6.36
in
2003; and $4.57 in 2002.
Electric
Utility Services
At
December 31, 2006, the Company supplied electric service to approximately
141,000 Indiana customers, including 122,000 residential, 18,800 commercial,
and
200 industrial and other customers. This represents customer base growth of
1%
compared to 2005. In addition, the Company has firm power commitments to four
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, 2006, retail and firm wholesale electricity sales
totaled 6,004.5 GWh, resulting in revenues of approximately $392.5 million.
Residential customers accounted for 25% of 2006 revenues; commercial 22%;
industrial 43%; and municipal and other 10%. In addition, the Company sold
898.3
GWh through optimization activities in 2006, generating revenue, net of
purchased power costs, of $29.7 million.
Generating
Capacity
Installed
generating capacity as of December 31, 2006, was rated at 1,301 MW. Coal-fired
generating units provide 1,006 MW of capacity, and natural gas or oil-fired
turbines used for peaking or emergency conditions provide 295 MW.
In
addition to its generating capacity, in 2006, the Company had 34 MW available
under firm contracts and 62 MW available under interruptible contracts. The
Company also had a firm purchase supply contract for a maximum of 73 MW for
the
cooling season months during 2006. This contract ended at the end of September
2006. Also, under the terms of the consent decree between SIGECO, the Department
of Justice and USEPA, the Company discontinued operations of Culley Unit 1
(50
MW) effective December 31, 2006. The Company executed a capacity contract for
a
maximum of 100 MW for the years 2007-2009.
The
Company has interconnections with Louisville Gas and Electric Company, Cinergy
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.
Total
load for each of the years 2002 through 2006 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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8/10/2006
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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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8/5/2002
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Total
load at peak (1)
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1,325
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1,315
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1,222
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1,272
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1,258
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|||||||||||
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Generating
capability
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1,351
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1,351
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1,351
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1,351
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1,351
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|||||||||||
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Firm
purchase supply
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107
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107
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105
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32
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82
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|||||||||||
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Interruptible
contracts
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62
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76
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51
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95
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95
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|||||||||||
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Total
power supply capacity
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1,520
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1,534
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1,507
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1,478
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1,528
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|||||||||||
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Reserve
margin at peak
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15
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%
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17
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%
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23
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%
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16
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%
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21
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%
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||||||
| (1) |
The
total load at peak is increased 25 MW in 2006, 2005, 2003, and 2002
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 2005-2006 season of approximately 935 MW occurred
on
December 20, 2005. The prior year winter peak load was approximately 932 MW,
occurring on January 18, 2005.
The
Company maintains a 1.5% 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% interest in the OVEC makes available approximately 34 MW of
capacity, in addition to its generating capacity, for use in other operations.
Such generating capacity is included in firm purchase supply in the chart
above.
Fuel
Costs and Purchased Power
Electric
generation for 2006 was fueled by coal (98%) and natural gas (2%). Oil was
used
only for testing of gas/oil-fired peaking units.
There
are
substantial coal reserves in the southern Indiana area, and coal for coal-fired
generating stations has been supplied from operators of nearby Indiana coal
mines, including those owned by Vectren Fuels, Inc., a wholly owned subsidiary
of the Company. Approximately 3.5 million tons of coal were purchased for
generating electricity during 2006, of which approximately 91% 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 2002 through 2006
follows:
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Year
Ended December 31,
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||||||||||||||||
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Avg.
Cost Per
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2006
|
|
2005
|
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2004
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2003
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2002
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|||||||
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Ton
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$
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37.51
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$
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30.27
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$
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27.06
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$
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24.91
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$
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23.50
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||||||
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MWh
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18.44
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14.94
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13.06
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11.93
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11.00
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|||||||||||
The
Company also purchases power as needed from the wholesale market to supplement
its generation capabilities in periods of peak demand; however, the majority
of
power purchased through the wholesale market is used to optimize and hedge
the
Company’s sales to other wholesale customers. Volumes purchased in 2006
totaled 434,234 MWh.
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, including Ohio, 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, 2006, approximately 72,000 customers in Utility Holdings’ 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.
Regulatory
and Environmental Matters
See
“Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s regulated environment and other environmental
matters.
Personnel
As
of
December 31, 2006, the Company and its consolidated subsidiaries had 1,599
employees, of which 828 are subject to collective bargaining arrangements.
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
July
2004, the Company reached a three-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2007. 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.
No
contracts subject to collective
bargaining expired
in 2006. The next negotiation will be with the International
Brotherhood
of
Electrical Workers Local
702,
whose contract expires in June of 2007.
ITEM
1A. RISK FACTORS
The
following factors 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.
The
Company is a holding company, and its assets consist primarily of investments
in
its subsidiaries.
Dividends
on the Company’s common stock depend on the earnings, financial condition,
capital requirements and cash flow of its subsidiaries, Indiana Gas, SIGECO
and
VEDO, and the distribution or other payment of earnings from those entities
to
the Company. Should the earnings, financial condition, or capital requirements
of, or legal requirements applicable to, them restrict their ability to pay
dividends or make other payments to Utility Holdings, the Company’s ability to
pay dividends to its parent could be adversely affected. Utility Holdings'
results of operations, future growth and earnings and dividend goals also will
depend on the performance of its subsidiaries.
The
Company 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 the Company’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. The Company cannot provide any assurance
that
increased competition or other changes in legislation, regulation or policies
will not have a material adverse effect on its business, financial condition
or
results of operations.
A
significant portion of the Company’s gas and electric utility sales are space
heating and cooling. Accordingly, its operating results may fluctuate with
variability of weather.
The
Company’s gas and electric utility sales are sensitive to variations in weather
conditions. Utility Holdings' forecasts utility sales on the basis of normal
weather, which represents a long-term historical average. Since the Company
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 its Indiana territories has been significantly mitigated
through the implementation on October 15, 2005, of a normal temperature
adjustment mechanism.
The
Company’s gas and electric utility sales are concentrated in the
Midwest.
The
operations of the Company’s regulated utilities are concentrated in central and
southern Indiana and west central Ohio and are therefore impacted by changes
in
the Midwest economy in general and changes in particular industries concentrated
in the Midwest. These industries include automotive assembly, parts and
accessories, feed, flour and grain processing, metal castings, aluminum
products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic
products, gypsum products, electrical equipment, metal specialties, glass,
steel
finishing, pharmaceutical and nutritional products, gasoline and oil products,
and coal mining.
Risks
related to the regulation of the Company’s 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, the Company is subject to regulation
by
the FERC, the IURC and the PUCO. These authorities regulate many aspects of
its
transmission and distribution operations, including construction and maintenance
of facilities, operations, safety, and the rates that the Company can charge
customers and the rate of return that its utilities are authorized to earn.
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.
In
addition, 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. Any future legislative or regulatory actions taken
to
address global climate change could adversely affect Utility Holdings’ business
and results of operations by, for example, requiring changes in, and increased
costs related to, the Company’s fossil fuel generating plants.
From
time to time, Utility Holdings is subject to material litigation and regulatory
proceedings.
The
Company may be subject to material litigation and regulatory proceedings from
time to time. There can be no assurance that the outcome of these matters will
not have a material adverse effect on its business, results of operations or
financial condition.
The
Company’s electric operations are subject to various risks.
The
Company’s electric generating facilities are subject to operational risks that
could result in unscheduled plant outages, unanticipated operation and
maintenance expenses and increased 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.
Utility
Holdings may experience significantly increased gas costs.
Commodity
prices for natural gas purchases have increased and become more volatile in
recent years. Subject to regulatory approval, Utility Holdings’ subsidiaries are
allowed recovery of gas costs from their retail customers through
commission-approved gas cost adjustment mechanisms. As a result, profit margins
on gas sales are not expected to be impacted. Nevertheless, regulators may
disallow, and have in the past disallowed, recovery of a portion of gas costs
for various reasons, including but limited to, a finding by the regulator that
natural gas was not prudently procured, as an example. In addition, it is
possible that as a result of this near term change in natural gas commodity
prices, the Company’s subsidiaries may experience increased interest expense due
to higher working capital requirements, increased uncollectible accounts expense
and unaccounted for gas and some level of price sensitive reduction in volumes
sold or delivered. However, the Company believes that the negative earnings
impact on the reduction of price sensitive natural gas volumes sold is
significantly mitigated by Indiana and Ohio orders received in the fourth
quarter of 2006 that authorize lost margin recovery.
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 Utility Holdings’ 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, Utility Holdings now bids its owned
generation into the Day Ahead and Real Time markets and procure power for its
retail customers at Locational Marginal Pricing (LMP) as determined by the
MISO
market.
As
a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including Utility Holdings’ electric transmission facilities,
its 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 uncertainties around Day 2 energy market operations, it
is
difficult to predict near term operational impacts. However, it is believed
that
MISO’s regional operation of the transmission system will ultimately lead to
reliability improvements within the Midwestern transmission system.
The
potential 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 will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
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.
Projected 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 the Company’s facilities and
operations.
Catastrophic
events such as fires, earthquakes, explosions, floods, tornados, terrorist
acts
or other similar occurrences could adversely affect Utility Holdings’ facilities
and 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 in the Company’s credit rating could negatively affect its ability to
access capital.
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, Indiana Gas and SIGECO senior unsecured debt
|
Baa1
|
A-
|
|
Utility
Holdings commercial paper program
|
P-2
|
A-2
|
The
current outlook of both Moody’s and Standard and Poor’s is stable and are
categorized 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 withdraw its ratings,
it
may significantly limit Utility Holdings’ access to the debt capital markets and
the commercial paper market, and the Company’s borrowing costs would increase.
In addition, Utility Holdings would likely be required to pay a higher interest
rate in future financings, and its potential pool of investors and funding
sources would likely decrease. Finally, there is no assurance that the Company
will have access to the equity capital markets to obtain financing when
necessary or desirable.
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 17.8 BCF of storage with a maximum
peak day delivery capability of 299,717 MMBTU per day. Indiana Gas’ gas delivery
system includes 12,505 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
108,000 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 3,166 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
.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 12.0 BCF of storage with
a
maximum peak day delivery capability of 246,080 MMBTU per day. The Ohio
operations’ gas delivery system includes 5,356 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, 2006, was rated at 1,301 MW.
SIGECO's coal-fired generating facilities are the Brown Station with two units
of 500 MW of combined capacity, located in Posey County approximately eight
miles east of Mt. Vernon, Indiana; the Culley Station with two
units
of 356 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.
Pursuant to the settlement between the Company, the Department of Justice,
and
the USEPA, the Company ceased operation of Culley Unit 1, with generating
capacity of 50 MW, effective December 31, 2006 and is excluded from the total
capacity above.
SIGECO's
transmission system consists of 894 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 30 substations with an installed
capacity of 5,057 megavolt amperes (Mva). The electric distribution system
includes 4,199 pole miles of lower voltage overhead lines and 331 trench miles
of conduit containing 1,833 miles of underground distribution cable. The
distribution system also includes 99 distribution substations with an installed
capacity of 2,010 Mva and 52,449 distribution transformers with an installed
capacity of 2,448 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, and 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
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.
During
2005, Utility Holdings paid dividends to its parent company of $20.0 million
in
each of the first, second and third quarters, and $20.7 million in the fourth
quarter.
On
January 31, 2007, the board of directors declared a $19.1 million dividend,
payable to Vectren on February 28, 2007.
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.
Debt
Security
The
Company’s 7 ¼% Senior Notes, due October 15, 2031, which were called in October
2006, previously traded on the New York Stock Exchange under the symbol “AVU.”
The high and low sales prices for the Company’s publicly traded debt security as
reported on the New York Stock Exchange are shown in the following table for
the
periods indicated.
|
Price
Range
|
Price
Range
|
|||||||||||||||
|
2006
|
High
|
|
Low
|
|
2005
|
|
High
|
|
Low
|
|||||||
|
First Quarter
|
$
|
25.59
|
$
|
25.00
|
First
Quarter
|
$
|
26.74
|
$
|
25.44
|
|||||||
|
Second Quarter
|
26.00
|
24.72
|
Second
Quarter
|
26.30
|
25.40
|
|||||||||||
|
Third Quarter
|
25.40
|
24.81
|
Third
Quarter
|
26.35
|
25.05
|
|||||||||||
|
Fourth Quarter
|
-
|
-
|
Fourth
Quarter
|
25.80
|
25.00
|
|||||||||||
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)
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
||||||
|
Operating
Data:
|
||||||||||||||||
|
Operating
revenues
|
$
|
1,656.5
|
$
|
1,781.8
|
$
|
1,498.0
|
$
|
1,448.8
|
$
|
1,236.9
|
||||||
|
Operating
income
|
209.0
|
216.6
|
196.3
|
197.2
|
207.7
|
|||||||||||
|
Net
income
|
91.4
|
95.1
|
83.1
|
85.6
|
97.1
|
|||||||||||
|
Balance
Sheet Data:
|
||||||||||||||||
|
Total
assets
|
$
|
3,440.8
|
$
|
3,391.2
|
$
|
3,147.7
|
$
|
2,925.1
|
$
|
2,780.4
|
||||||
|
Redeemable
preferred stock
|
-
|
-
|
0.1
|
0.2
|
0.3
|
|||||||||||
|
Long-term
debt - net of current maturities
|
||||||||||||||||
|
& debt subject to tender
|
1,025.3
|
997.8
|
941.3
|
960.5
|
841.2
|
|||||||||||
|
Common
shareholder's equity
|
1,056.7
|
1,023.8
|
985.4
|
979.8
|
768.6
|
|||||||||||
ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
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
For
the
year ended December 31, 2006, earnings were $91.4 million as compared to $95.1
million in 2005 and $83.1 million in 2004. The decline in 2006 results compared
to 2005 is primarily due to continued declines in customer usage. Results
reflect the impact of a constructive regulatory environment. The Company
received orders in the fourth quarter of 2006 that authorize lost margin
recovery related to the Company’s Ohio customers and a majority of Indiana
natural gas customers, and an order in the fourth quarter of 2005 for a normal
temperature adjustment mechanism with respect to the Company’s Indiana natural
gas customers. The Company also utilizes rider mechanisms to recover capital
expenditures associated with compliance with Clean Air Act and Clean Air Mercury
requirements, among other costs. In addition, the Company has implemented base
rate increases since 2003 and currently has two cases before the IURC where
orders are expected in 2007. The revenue increases, including the proposed
increases in the two pending cases, are required to offset increased operating
and financing costs, the effect on usage from higher commodity prices, and
the
impact of recent weather unfavorable compared to 30-year normal
temperatures.
Gas
utility base rate increases added revenues of approximately $4.2 million in
2006
compared to 2005, and $33.8 million in 2005 compared to 2004. Increased revenues
associated with recovery of pollution control investments were $2.6 million
in
2006 compared to 2005 and $14.3 million in 2005 compared to 2004. Increased
revenues associated with lost margin recovery were $2.0 million in 2006 compared
to 2005.
In
addition
to customer usage declines, the decrease in earnings in 2006 was
also
impacted by higher depreciation and interest costs, and wholesale power
marketing margins $6.2 million, or $3.7 million after tax, lower than the prior
year. 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
2005
compared to 2004, the $12 million increase is largely due to increased base
rates, recovery of pollution control investments, weather, and wholesale power
marketing activities. The improved utility margins were partially offset by
higher operating and depreciation expense. The 2005 results also reflect a
$4.1
million, $2.4 million after tax, charge recorded pursuant to the disallowance
of
Ohio gas costs.
In
2006,
2005, and 2004 weather across all utilities was unfavorable compared to 30-year
normal temperatures. Management estimates the after tax effect of weather
compared to normal was unfavorable $4 million in 2006, unfavorable $3 million
in
2005, and unfavorable $7 million in 2004. The 2006 weather effect contains
the
full impact of a normal temperature adjustment (NTA) mechanism implemented
in
the Company’s Indiana natural gas service territories in the fourth quarter of
2005.
Utility
Holdings generates revenue primarily from the delivery of natural gas and
electric service to its customers. The 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. Results are impacted by weather
patterns in its service territory and general economic conditions both in its
service territory as well as nationally.
The
Company has in place a disclosure committee that consists of senior management
as well as financial management. The committee is actively involved in the
preparation and review of the Company’s SEC filings.
Significant
Fluctuations
Throughout
this discussion, the terms Gas utility margin and Electric utility margin are
used. Gas utility margin is calculated as Gas
utility revenues
less the
Cost
of gas sold.
Electric utility margin is calculated as Electric
utility revenues
less the
Cost
of fuel & purchased
power.
The
Company believes Gas utility and Electric utility margins are better indicators
of relative contribution than revenues since gas prices and fuel costs can
be
volatile and are generally collected on a dollar-for-dollar basis from
customers. These measures exclude Other
operating expenses, Depreciation and amortization, and
Taxes other than income taxes,
which
are included in the calculation of operating income.
Margin
generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and is impacted by weather patterns in the
Company’s service territories. The weather impact in the Company’s Indiana gas
utility service territories is mitigated by a normal temperature adjustment
mechanism, which was implemented in the fourth quarter of 2005. Margin generated
from sales to large customers (generally industrial, other contract, and firm
wholesale customers) is primarily impacted by overall economic conditions.
Margin is also impacted by the collection of state mandated taxes, which
fluctuate with gas costs, as well as other tracked expenses and is also impacted
by some level of price sensitivity in volumes sold or delivered. 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)
|
2006
|
|
2005
|
|
2004
|
|||||
|
Gas
utility revenues
|
$
|
1,232.5
|
$
|
1,359.7
|
$
|
1,126.2
|
||||
|
Cost
of gas sold
|
841.5
|
973.3
|
778.5
|
|||||||
|
Total
gas utility margin
|
$
|
391.0
|
$
|
386.4
|
$
|
347.7
|
||||
|
Margin
attributed to:
|
||||||||||
|
Residential
& commercial customers
|
$
|
330.2
|
$
|
333.2
|
$
|
297.7
|
||||
|
Industrial
customers
|
48.0
|
48.3
|
45.7
|
|||||||
|
Other
customers
|
12.8
|
4.9
|
4.3
|
|||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||
|
Residential
& commercial customers
|
97.7
|
112.9
|
114.5
|
|||||||
|
Industrial
customers
|
84.9
|
87.2
|
85.8
|
|||||||
|
Total
sold & transported volumes
|
182.6
|
200.1
|
200.3
|
|||||||
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 normal temperature adjustment mechanism (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. The average cost per dekatherm of gas
purchased for the year ended December 31, 2006, was $8.64 compared to $9.05
in
2005 and $6.92 in 2004.
For
the
year ended December 31, 2005, gas utility margins increased $38.7 million
compared to 2004. The increase is primarily due to the favorable impact of
gas
base rate increases of $33.8 million and additional pass through expenses and
revenue taxes recovered in margins of $5.8 million compared to 2004. Results
for
the year ended December 31, 2005, reflect the disallowance of Ohio gas costs
ordered by the PUCO described above. For the year ended December 31, 2005,
weather was 5% warmer than normal but 4% colder than the prior year. Management
estimates that weather, including the effects of the normal temperature
adjustment mechanism, increased margin an estimated $2.5 million compared to
2004.
Electric
Utility Margin (Electric utility
revenues less Cost of fuel & purchased power)
Electric
Utility margin by revenue type follows:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|||||
|
Electric
utility revenues
|
$
|
422.2
|
$
|
421.4
|
$
|
371.3
|
||||
|
Cost
of fuel & purchased power
|
151.5
|
144.1
|
116.8
|
|||||||
|
Total
electric utility margin
|
$
|
270.7
|
$
|
277.3
|
$
|
254.5
|
||||
|
Margin
attributed to:
|
||||||||||
|
Residential
& commercial customers
|
$
|
162.9
|
$
|
170.8
|
$
|
157.3
|
||||
|
Industrial
customers
|
70.2
|
66.9
|
63.7
|
|||||||
|
Municipal
& other customers
|
24.0
|
19.8
|
18.6
|
|||||||
|
Subtotal:
Retail & firm wholesale
|
$
|
257.1
|
$
|
257.5
|
$
|
239.6
|
||||
|
Asset
optimization
|
$
|
13.6
|
$
|
19.8
|
$
|
14.9
|
||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||
|
Residential
& commercial customers
|
2,789.7
|
2,933.2
|
2,830.9
|
|||||||
|
Industrial
customers
|
2,570.4
|
2,575.9
|
2,511.2
|
|||||||
|
Municipal
& other customers
|
644.4
|
689.9
|
645.9
|
|||||||
|
Total
retail & firm wholesale volumes sold
|
6,004.5
|
6,199.0
|
5,988.0
|
|||||||
Retail
& Firm Wholesale Margin
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
heating weather). During 2006, cooling degree days were 5% below normal. In
2005, cooling degree days were 9% above normal.
Electric
retail and firm wholesale utility margin increased $17.9 million in 2005
compared to 2004. The recovery of pollution control related investments and
associated operating expenses and depreciation expense increased margins $14.3
million compared to 2004. Cooling weather was 9% warmer than normal and 21%
warmer than 2004. In 2005 compared to 2004, the estimated increase in electric
margin related to weather was $4.0 million ($3.8 million related to cooling
weather and $0.2 million related to heating weather).
Margin
from Asset Optimization Activities
Periodically,
generation capacity is in excess of that needed to serve retail load and firm
wholesale customers. The Company markets this unutilized capacity to optimize
the return on its owned generation assets. These optimization strategies
primarily 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 are integrated with portfolio requirements around power
supply and delivery.
Following
is a reconciliation of asset optimization activity:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
|
2006
|
|
2005
|
|
2004
|
||||
|
Off-system
sales
|
$
|
14.2
|
$
|
15.3
|
$
|
8.7
|
||||
|
Transmission
system sales
|
3.5
|
4.5
|
4.6
|
|||||||
|
Other
|
(4.1
|
)
|
0.0
|
1.6
|
||||||
|
Total asset optimization
|
$
|
13.6
|
$
|
19.8
|
$
|
14.9
|
||||
For
the
year ended December 31, 2006, net asset optimization margins were $13.6 million,
which represents a decrease of $6.2 million compared to 2005. The decrease
is
due to the effect lower wholesale prices have had on the Company’s optimization
portfolio and lower volumes sold off system. For the year ended December 31,
2005, net asset optimization margins increased $4.9 million as compared to
2004.
The increase in margin results primarily from the timing of available capacity
and mark to market gains.
In
2005,
the Company experienced increased availability of the generating units. The
availability of excess capacity was reduced in 2006 and 2004 by scheduled
outages of owned generation related to the installation of environmental
compliance equipment. Off-system sales totaled 889.4 GWh in 2006, compared
to
1,208.1 GWh in 2005 and 670.4 GWh in 2004.
Operating
Expenses
Other
Operating
For
the
year ended December 31, 2006, other operating expenses decreased $2.3 million
compared to 2005. Expenses in 2006 are reduced from the inclusion of a gain
on
the sale of a storage asset of approximately $4.4 million. Excluding this gain,
operating expenses would have increased $2.1 million compared to 2005. The
increase is primarily the result of electric generation chemical costs $1.3
million higher than the prior year. Bad debt expense in the Company’s Indiana
service territories increased $0.6 million year over year due in part to higher
gas costs.
Other
operating expenses increased $20.9 million for the year ended December 31,
2005,
compared to 2004. Amortization of rate case expenses, expenses associated with
the Ohio choice program and integrity management programs, and expenses
recovered through margin increased $6.5 million. Bad debt expense in the
Company’s Indiana service territories was $9.3 million in 2005, an increase of
$1.8 million compared to 2004. Compensation and benefit costs increases,
including performance and share-based compensation, was $6.8 million higher
than
the prior year, reflective of the return to higher earnings in 2005 as compared
to 2004. Higher maintenance, chemical costs, and all other costs account for
$5.8 million of the increase.
Depreciation
& Amortization
Depreciation
expense increased $10.0 million in 2006 compared to 2005 and $13.5 million
in
2005 compared to 2004. In addition to depreciation on additions to plant in
service, the increases were primarily due to incremental depreciation expense
associated with environmental compliance equipment additions. Depreciation
expense associated with environmental compliance equipment, which is recovered
in Electric
utility margin,
totaled
$14.4 million in 2006, $12.1 million in 2005, and $6.2 million in 2004. Results
for 2004 include $1.8 million of lower depreciation due to adjustments of Ohio
depreciation rates and amortization of Indiana regulatory assets.
Taxes
Other Than Income Taxes
Taxes
other than income taxes decreased $1.0 million for the year ended December
31,
2006, compared to 2005 and increased $7.0 million in 2005 compared to 2004.
The
fluctuations are primarily attributable to variations in the collection of
utility receipts, excise, and usage taxes. These variations resulted primarily
from volatility in revenues and gas volumes sold.
Other
Income (Expense)
Total
other income (expense)-net increased $1.7 million in 2006 compared to 2005,
and
decreased $1.4 million in 2005 compared to 2004. The fluctuations relate
primarily to capitalized interest on utility plant additions.
Interest
Expense
In
2006,
interest expense increased $7.6 million compared to 2005 and increased $2.5
million in 2005 compared to 2004. The increases are primarily driven by rising
interest rates and higher levels of short-term borrowings due in part to higher
working capital requirements resulting from the increased gas commodity prices.
Interest
costs in 2006 also include the full impact of 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. Results for 2006 also include a partial impact from financing
transactions completed in October 2006 in which approximately $93 million in
debt related proceeds were raised and used to retire debt outstanding with
a
higher interest rate.
Income
Taxes
Federal
and state income taxes decreased $9.8 million in 2006 compared to 2005 and
increased $4.4 million in 2005 compared to 2004. The changes are impacted by
fluctuations in pre-tax income. Income taxes recorded in 2006 reflect 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, nor is it possible to predict what other regulations may
be
adopted in the future, including any regulations to address the climate change
issue.
Clean
Air Act
Clean
Air Interstate Rule & Clean Air Mercury Rule
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. The Company is evaluating compliance options and fully expects to be
in
compliance by the required deadlines.
In
February 2006, the IURC approved a multi-emission compliance plan filed by
the
Company’s utility subsidiary, SIGECO. Once the plan is implemented, SIGECO’s
coal-fired plants will be 100% scrubbed for SO2,
90%
scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury
reduction standards. The order, as previously agreed to by the OUCC and Citizens
Action Coalition, allows SIGECO to recover an approximate 8% return on up to
$110 million in capital investments through a rider mechanism which is updated
every six months for actual costs incurred. The Company will also recover
through a rider its operating expenses, including depreciation, once the
equipment is placed into service. The order also stipulates that SIGECO study
renewable energy alternatives and include a carbon forecast in future filings
with regard to new generation and further environmental compliance plans, among
other initiatives. As of December 31, 2006, the Company has made capital
investments of approximately $62.2 million related to this environmental
requirement.
NOx
SIP Call Matter
The
Company complied with Indiana’s State Implementation Plan (SIP) of the Clean Air
Act (the Act). These steps included installation of Selective Catalytic
Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick
Generating Station Unit 4, and A. B. Brown Generating Station Units 1 and 2.
SCR
systems reduce flue gas NOx emissions to atmospheric nitrogen and water using
ammonia in a chemical reaction. This technology is known to currently be the
most effective method of reducing nitrogen oxide (NOx) emissions where high
removal efficiencies are required.
The
IURC
issued orders that approved:
| · |
the
Company’s project to achieve environmental compliance by investing in
clean coal technology;
|
| · |
the
Company’s investment of $258 million in capital
costs;
|
| · |
a
mechanism whereby, prior to an electric base rate case, the Company
recovers through a rider that is updated every six months, an 8%
return on
its weighted capital costs for the project; and
|
| · |
ongoing
recovery of operating costs, including depreciation and purchased
emission
allowances, related to the clean coal technology now that facilities
are
placed into service.
|
Related
annual operating expenses, including depreciation expense, were $18.7 million
in
2006, $15.4 million in 2005, and $9.7 million in 2004.
Culley
Generating Station Litigation
During
2003, the U.S. District Court for the Southern District of Indiana entered
a
consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA
that
resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit
alleged violations of the Clean Air Act by SIGECO at its Culley Generating
Station for (1) making modifications to a generating station without obtaining
required permits, (2) making major modifications to the generating station
without installing the best available emission control technology, and (3)
failing to notify the USEPA of the modifications.
Under
the
terms of the agreement, the DOJ and USEPA agreed to drop all challenges of
past
maintenance and repair activities at the Culley Generating Station. In reaching
the agreement, SIGECO did not admit to any allegations in the government’s
complaint, and SIGECO continues to believe that it acted in accordance with
applicable regulations and conducted only routine maintenance on the units.
SIGECO entered into this agreement to further its continued commitment to
improve air quality and avoid the cost and uncertainties of litigation.
Under
the
agreement, SIGECO committed to:
| · |
either
repower Culley Unit 1 (50 MW) with natural gas and equip it with
SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31,
2006;
|
| · |
operate
the existing SCR control technology recently installed on Culley
Unit 3
(287 MW) year round at a lower emission rate than that currently
required
under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
|
| · |
enhance
the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide
emissions;
|
| · |
install
a baghouse for further particulate matter reductions at Culley Unit
3 by
June 30, 2007;
|
| · |
conduct
a Sulphuric Acid Reduction Demonstration Project as an environmental
mitigation project designed to demonstrate an advance in pollution
control
technology for the reduction of sulfate emissions; and
|
| · |
pay
a $600,000 civil penalty.
|
The
Company does not believe that implementation of the settlement will have a
material effect on its results of operations or financial condition. The
$600,000 civil penalty was expensed and paid during 2003. The Company ceased
operation of Culley Unit 1 effective December 31, 2006 and the baghouse, which
is included in the $110 million IURC order discussed above, went into service
January 1, 2007.
Manufactured
Gas Plants
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 byproducts 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. Although
Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has
submitted several 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.
In
conjunction with data compiled by environmental consultants, 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 $20.4 million.
The
estimated accrued costs are limited to Indiana Gas’ proportionate 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% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 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 response, SIGECO submitted to the IDEM the
results of preliminary site investigations conducted in the mid-1990’s. These
site investigations confirmed that based upon the conditions known at the time,
the sites posed no imminent and/or substantial risk to human health or the
environment.
On
October 6, 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 on February 24, 2004. On July 13, 2004, SIGECO 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. 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 $7.7 million. With respect to insurance
coverage, SIGECO has received and recorded settlements from insurance carriers
in an aggregate amount approximating the costs it expects to incur.
Environmental
matters related to Indiana Gas’ and SIGECO’s manufactured gas plants 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.
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, if required by the USEPA.
Global
Climate Change
Global
climate change remains a policy issue that is regularly considered for
government regulation. If legislation requiring reductions in greenhouses gases
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel plants.
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.
All
metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all
metered gas 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.
Metered 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.
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. For the recent
past, the earnings test has not affected the Company’s ability to recover
costs.
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 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. This mechanism is 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 between the Company
and
the OUCC that provides for a 5-year energy efficiency program to be implemented.
The order allows the Company’s Indiana utilities to recover the costs of
promoting the conservation of natural gas through conservation trackers that
work in tandem with a lost margin recovery mechanism that would provide for
recovery of 85% of the difference between revenues actually collected by the
Company and the revenues approved in the Company’s most recent rate case. The
order was implemented in the North service territory in December 2006 and will
be implemented in South’s service territory after its next general rate case
(see below.) While most expenses associated with these programs are recoverable,
in the first program year, the Company is required to fund $1.5 million in
program costs without recovery. Revenues recorded in 2006 as a result of this
order related to lost margin recovery totaled $0.7 million and revenues to
fund
energy efficiency programs totaled $0.6 million.
Ohio
In
September 2006, the PUCO approved a conservation proposal that would implement
a
decoupling approach, including a related conservation program, for the Company’s
Ohio operations. The PUCO decision was issued following a hearing process and
the submission of a settlement by the Company, the Ohio Consumer Counselor
(OCC)
and the Ohio Partners for Affordable Energy (OPAE). That settlement was
contested by the PUCO Staff. In the decision the PUCO addressed decoupling
by
approving a two year, $2 million total, low-income conservation program to
be
funded 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. The decision produced an outcome that was
different from the settlement. Following the decision, the Company and the
OPAE
advised the PUCO that they would accept the outcome even though it differed
from
the terms of the settlement. The OCC sought rehearing of the decision, which
was
denied in December, and thereafter the OCC advised the PUCO that the OCC was
withdrawing from the settlement. At that point the OCC also initiated the
process for appealing the PUCO’s September and December decisions to the Ohio
Supreme Court. Thereafter, the Company, the OPAE and the PUCO Staff advised
the
PUCO that they accepted the terms provided in the September decision, as
affirmed by the December rehearing decision. Since that time there have been
a
number of procedural filings by the parties and presently the Company is
awaiting a further decision from the PUCO. The Company believes that the PUCO
had the necessary legal basis for its decisions and thus should confirm the
outcome provided in the September decision. The Company began recognizing the
impact of this order on October 1, 2006, and has recorded revenues in 2006
related to the order in the amount of $1.3 million.
Vectren
South (Southern Indiana Gas & Electric) Base Rate Filings
On
September 1, 2006, Vectren South filed
petitions with the IURC to adjust its electric and gas base rates in its South
service territory. The electric petition requests an increase of $76.7 million
in base rates to recover the nearly $120 million additional investment in
electric utility infrastructure since its last base rate increase in 1995,
which
is not currently included in rates charged to customers. The increase in rates
also is required to support system growth, maintenance, reliability and recovery
of costs deferred under previous IURC orders. The gas petition seeks to increase
its gas base (non-gas cost) rates by $10.4 million to cover the ongoing costs
of
operating and maintaining its natural gas distribution and storage system.
Based
upon the timelines prescribed by the IURC at the start of these proceedings,
decisions in each case are expected to be issued in the late summer of 2007.
The
initial public hearings in both cases have been conducted. On January 30, 2007,
the OUCC filed testimony in the gas rate case proposing an increase of $5.1
million.
Integrated
Gasification Combined Cycle (IGCC) Certificate of Public Convenience and
Necessity
On
September 7, 2006, Vectren Energy Delivery of Indiana and Duke Energy Indiana,
Inc. filed with the IURC a joint petition for a Certificate of Public
Convenience and Necessity (CPCN) for the construction of new electric capacity.
Specifically, Vectren requested the IURC approve its construction and ownership
of up to 20% of an IGCC project. Vectren's CPCN filing also seeks timely
recovery of its 20% portion of the project's construction costs as well as
operation and maintenance costs and additional incentives available for the
construction of clean coal technology. Initial studies of plant design have
already begun, and if the project moves forward as currently designed, plant
construction is expected to begin in 2007 and continue through 2011.
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% 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 will be adjusted
using the NTA. Resulting from this order, revenues recorded in 2006 totaled
$13.6 million while refunds of $1.6 million were made 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.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
Gas
Utility Base Rate Settlements in 2004 and 2005
On
June
30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas
distribution business, and on November 30, 2004, approved a $24 million base
rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the
PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution
business. The base rate change in SIGECO’s service territory was implemented on
July 1, 2004; the base rate change in Indiana Gas’ service territory was
implemented on December 1, 2004; and the base rate change in VEDO’s service
territory was implemented on April 14, 2005.
The
orders also permit SIGECO and Indiana Gas to recover the on-going costs to
comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety
Improvement Tracker provides for the recovery of incremental non-capital
dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO
and $2.5 million per year for Indiana Gas. Any costs incurred in excess of
these
annual caps are to be deferred for future recovery. VEDO’s new base rates
provide for the recovery of some level of on-going costs to comply with the
Pipeline Safety Improvement Act of 2002.
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.
Pursuant to an order from the IURC received in December 2001, certain MISO
startup costs (referred to as Day 1 costs) have been deferred for future
recovery in the next general rate case, which was filed in 2006.
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.
On
June
1, 2005, Vectren, together with three other Indiana electric utilities, received
regulatory authority from the IURC that allows recovery of fuel related costs
and deferral of 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. The other non-fuel and MISO
administrative related costs are to be deferred for recovery as part of the
next
electric general rate case proceeding, which was filed in 2006. During 2006,
the
IURC reaffirmed the definition of certain costs as fuel related; the Company
is
following those guidelines.
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 uncertainties around Day 2 energy market operations, it
is
difficult to predict near term operational impacts. However, as stated above,
it
is believed that MISO’s regional operation of the transmission system will
ultimately lead to reliability improvements.
The
potential 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 will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
Gas
Cost Recovery (GCR) Audit Proceedings
On
June
14, 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 November
2002. That audit period provided the PUCO staff its initial review of the
portfolio administration arrangement between VEDO and ProLiance. The
disallowance includes approximately $1.3 million relating to pipeline refunds
and penalties and approximately $4.5 million of costs for winter delivery
services purchased by VEDO to ensure reliability over the two-year period.
The
PUCO also held that ProLiance should have credited to VEDO an additional $3.8
million more than credits actually received for the right to use VEDO’s gas
transportation capacity periodically during the periods when it was not required
for serving VEDO’s customers. The PUCO also directed VEDO to either submit its
receipt of portfolio administration services to a request for proposal process
or to in-source those functions. During 2003, the Company recorded a reserve
of
$1.1 million for this matter. An additional pretax charge of $4.1 million was
recorded in
Cost
of gas sold
in 2005.
The reserve reflects management’s assessment of the impact of the PUCO
decisions, an estimate of any current impact that decision may have on
subsequent audit periods, and an estimate of a sharing in any final disallowance
by Vectren’s partner in ProLiance.
VEDO
filed its request for rehearing on July 14, 2005, and on August 10, 2005, the
PUCO granted rehearing to further consider the $3.8 million portfolio
administration issue and all interest on the findings, but denied rehearing
on
all other aspects of the case. On October 7, 2005, the Company filed an appeal
with the Ohio Supreme Court requesting that the $4.5 million disallowance
related to the winter delivery service issue be reversed. On December 21, 2005,
the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million
disallowance related to portfolio administration to $1.98 million. The Company
has appealed the $1.98 million disallowance to the Ohio Supreme Court as well.
Briefings of all matters and oral arguments were completed in November 2006,
and
the parties are awaiting the Court’s ruling.
With
respect to the most recent GCR audit covering the period of November 1, 2002
through October 31, 2005, the PUCO staff recommended a disallowance of
approximately $830,000 related solely to the retention of a reserve margin
for
the winter of 2002/2003. The Company had previously reserved for the possible
disallowance given the June 2005 PUCO order but has contested the disallowance.
The PUCO will issue a decision on that issue in 2007.
As
a
result of the 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.
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 depreciation of utility and
non-utility plant, the valuation of derivative contracts, and the allowance
for
doubtful 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
12
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 2006, 2005, and
2004 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.
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. In the
unlikely event of a change in the current regulatory environment, such
write-offs and impairment charges could be significant.
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 by Vectren’s actuaries, 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. These costs are directly
charged to individual subsidiaries. Other components of costs (such as interest
cost and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Neither plan assets nor the ending
liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. Management believes
these direct charges when combined with benefit-related corporate charges
discussed in “support services” above approximate costs that would have been
incurred if the Company accounted for benefit plans on a stand-alone basis.
Vectren
estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other inputs, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of pension and postretirement plans. Vectren annually
measures its obligations on September 30, and used the following weighted
average assumptions to develop 2006 periodic benefit cost: a discount rate
of
5.50 percent, an expected return on plan assets of 8.25 percent, a rate of
compensation increase of 3.25 percent, and an inflation assumption of 3.50
percent. During 2006, Vectren increased the discount rate by 35 basis points
to
value 2006 ending pension and postretirement obligations and 2007 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 have
increased 2006 periodic benefit cost by approximately $1.3 million.
Impact
of Recently Issued Accounting Guidance
SFAS
No. 158
On
December 31, 2006,
and
after
calculating the balance sheet impact of Vectren's retirement plans using the
accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted
SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and
132(R)” (SFAS 158). SFAS 158 required Vectren to recognize the funded
status of its pension plans and postretirement plans. SFAS 158 defines the
funded status of a defined benefit plan as its assets less its projected benefit
obligation, which includes projected salary increases, and defines the funded
status of a postretirement plan as its assets less its accumulated
postretirement benefit obligation. The impacts of adopting this standard were
recorded at Vectren and are not reflected at the Utility Holdings level.
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, and interim periods
within those fiscal years with early adoption encouraged. The
Company is currently assessing the impact this statement will have on its
financial statements and results of operations.
FIN
48
In
June
2006, the FASB issued 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.
The interpretation is effective for fiscal years beginning after December 15,
2006. The adoption of this standard is not expected to have a material impact
on
operating results or financial condition.
Financial
Condition
Utility
Holdings, the parent company, funds the short-term and long-term financing
needs
of its consolidated operations. Vectren does not guarantee Utility Holdings’
debt. Utility Holdings’ currently outstanding long-term and short-term borrowing
arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and
VEDO. The guarantees are full and unconditional and joint and several, and
Utility Holdings has no subsidiaries other than the subsidiary guarantors.
Utility Holdings’ long-term and short-term obligations outstanding at December
31, 2006, totaled $700.0 million and $270.1 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 on outstanding senior unsecured debt of Utility Holdings and
Indiana Gas, at December 31, 2006, are A-/Baa1 as rated by Standard and Poor's
Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s),
respectively. SIGECO's credit ratings on outstanding 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% of long-term
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, execution
of
long-term financing plans, and seasonal factors that affect the Company’s
operations. The Company’s equity component was 50% and 49% of long-term
capitalization at December 31, 2006, and 2005, respectively. Long-term
capitalization includes long-term debt, including current maturities and debt
subject to tender, as well as common shareholders’ equity.
The
Company expects a significant portion 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
will likely require additional permanent financing. As of December 31, 2006,
the
Company was in compliance with all financial covenants.
Sources
& Uses of Liquidity
Operating
Cash Flow
The
Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations, which totaled $286.1
million in 2006 compared to $265.8 million in 2005 and $232.9 million in 2004.
The $20.3 million increase in cash flow 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.
Cash
flow
from operating activities increased $32.9 million in 2005 compared to 2004.
Increased cash flow from operating activities is due to increased earnings
before noncash charges and less cash utilized to support working capital
increases. Earnings before noncash charges were $289.2 million in 2005 compared
to $269.2 million in 2004, and cash utilized for working capital increases
was
$13.0 million in 2005 compared to $24.4 million in 2004.
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 long-term financing
arrangements executed in 2006 and 2005. In 2006, Utility Holdings issued $100
million of senior unsecured securities and used those proceeds to retire higher
coupon long-term debt. In 2005, Utility Holdings issued $150 million of senior
unsecured securities and used those proceeds to retire higher coupon long-term
debt and refinance certain capital projects originally financed with short-term
borrowings. In 2006 and 2005, Utility Holdings received an additional
capital contribution from Vectren totaling $20.0 million in
both
years. Utility Holdings used proceeds from
these capital contributions 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.
Utility
Holdings 2006
Debt Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95% 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 issued 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% 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%
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% priced
at
99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year
notes due December 2035 with an interest rate of 6.10% priced at 99.779% to
yield 6.11% 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% 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.
Additional
Capital Contributions
During
the years ended December 31, 2006, 2005, and 2004, the Company has cumulatively
received additional capital of $43.1 million from Vectren. Of that total, $40.0
million was funded by Vectren’s nonregulated operations, and $3.1 million was
funded by new share issues from Vectren’s dividend reinvestment
plan.
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 re-marketed. During 2006 and 2005, no debt was put to the
Company. During 2004, debt totaling $2.5 million 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, 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 quarterly senior unsecured notes originally due in 2030,
and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior
unsecured notes originally due in 2015. The notes called in 2006, 2005 and
2004
had stated interest rates of 7.25%, 7.45% and 7.15%, 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%
to
5.00%. After the remarketing, interest rates are reset every seven days using
an
auction process.
During
2004, the Company remarketed two first mortgage bonds outstanding at SIGECO.
The
remarketing effort converted $32.8 million of outstanding fixed rate debt into
variable rate debt where interest rates reset every seven days using an auction
process. One bond, due in 2023, had a principal amount of $22.8 million and
an
interest rate of 6%. The other bond, due in 2015, had a principal amount of
$10.0 million and an interest rate of 4.3%. These remarketing efforts resulted
in the extinguishment and reissuance of debt at generally the same par value.
Other
Company debt totaling $15.0 million in 2004 was retired as
scheduled.
Investing
Cash Flow
Cash
flow
required for investing activities was $249.9 million in 2006, $217.7 million
in
2005, and $242.7 million in 2004. Capital expenditures are the primary component
of investing activities. Capital expenditures were $250.0 in 2006 compared
to
$217.8 million in 2005 and $246.2 million in 2004. Expenditures in 2006 and
2004
include higher levels of expenditures for environmental compliance equipment.
Available
Sources of Liquidity
At
December 31, 2006, the Company has $520 million of short-term borrowing
capacity, of which approximately $250 million is available.
During
the fourth quarter of 2005, in response to higher natural gas prices, Utility
Holdings increased its available consolidated short-term borrowing capacity
to
$520 million, a $165 million increase over previous levels. In addition, Utility
Holdings extended the maturity of its largest credit facility, which totals
$515
million, through November 2010.
Vectren
periodically issues new shares to satisfy dividend reinvestment plan and stock
option plan requirements and contributes those proceeds to Utility Holdings.
During 2004, these new issuances added additional liquidity of $3.1 million.
Potential
& Future Uses of Liquidity
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2006:
|
(In
millions)
|
Total
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
||||||||
|
Long-term
debt (1)
|
$
|
1,055.7
|
$
|
6.5
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
250.0
|
$
|
799.2
|
||||||||
|
Short-term
debt
|
270.1
|
270.1
|
-
|
-
|
- | - |
-
|
|||||||||||||||
|
Long-term
debt interest commitments
|
919.6
|
62.7
|
62.5
|
62.5
|
62.5
|
61.1
|
608.3
|
|||||||||||||||
|
Plant
purchase commitments (2)
|
390.5
|
64.5
|
113.0
|
115.0
|
70.0
|
28.0
|
-
|
|||||||||||||||
|
Total
|
$
|
2,635.9
|
$
|
403.8
|
$
|
175.5
|
$
|
177.5
|
$
|
132.5
|
$
|
339.1
|
$
|
1,407.5
|
||||||||
| (1) |
Certain
long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow
holders
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 2006 (in millions) is $20.0 in 2007, zero in 2008,
$80.0
in 2009, $10.0 million in 2010, $30.0 in 2011 and zero
thereafter.
|
| (2) |
The
settlement period of these obligations is
estimated.
|
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase commodities 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.
Planned
Capital Expenditures
The
timing and amount of capital expenditures, including contractual purchase
commitments discussed above, for the five-year period 2007 - 2011 are estimated
as follows (in millions): $297.4 in 2007, $323.6 in 2008, $351.8 in 2009, $281.7
in 2010, and $222.7 in 2011.
Pension
and Postretirement Funding Obligations
Vectren
believes making contributions to its qualified pension plans in the coming
years
will be necessary. Management currently estimates that the qualified pension
plans will require Utility Holdings to contribute approximately $3 million
in
2007 and approximately $7 million in 2008. During 2006, Vectren made
contributions of $8.3 million, all of which were funded by Utility
Holdings.
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
supply 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 environment including 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
and other effects of legal and administrative proceedings, settlements,
investigations, claims, and other matters, including, but not limited
to,
those described in Management’s Discussion and Analysis of Results of
Operations and Financial
Condition.
|
| · |
Changes
in federal, state or local legislative requirements, such as changes
in
tax laws or rates, environmental laws and
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. QUANTITATIVE AND QUALITATIVE 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 also executes 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
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 the cost of such purchases through natural
gas and fuel cost adjustment mechanisms. Nevertheless, it is possible regulators
may disallow recovery of a portion of gas costs for various reasons, including
but not limited to, a finding by the regulator that natural gas was not
prudently procured, as an example. 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 or
delivered. The Company mitigates these risks by executing derivative contracts
that manage 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. Constructive regulatory orders, such as the Indiana
and Ohio orders authorizing lost margin recovery, also mitigate these risks.
When regulation is involved, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
Commodity
prices for natural gas purchases have remained above historical levels and
continue to be more volatile. Despite
hedging strategies, this near term change in natural gas commodity prices may
have significant effects on operating results as described above.
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.
Market
risk resulting from commodity contracts is measured by management using the
potential impact on pre-tax earnings caused by the effect a 10% adverse change
in forward commodity prices might have on market sensitive derivative positions
outstanding on specific dates. For the year ended December 31, 2005, a 10%
adverse change in forward commodity prices would have decreased earnings by
$0.3
million based upon open positions existing on the last day of that year. No
such
derivative contracts were outstanding on December 31, 2006.
Sales
to Municipalities and Other Industrial Customers
The
Company purchases and sells electricity to meet the demands of certain
municipalities and large industrial customers. 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 20% and 30% of its total debt to be exposed to
variable rate volatility. However, there are times when this targeted range
of
interest rate exposure may not be attained. To manage this exposure, the Company
may use derivative financial instruments. At December 31, 2006, debt subject
to
short-term interest rate volatility and seasonal increases in short-term debt
outstanding, represented 27% of the Company's total debt portfolio.
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 2006 and 2005, the weighted average combined
borrowings under these arrangements were $263.6 million and $225.9 million,
respectively. At December 31, 2006, and 2005, combined borrowings under these
arrangements were $351.7 million and $259.3 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2006 and 2005, an increase of 100 basis points (one percentage point) in
the
rates would have increased interest expense by $2.6 million and $2.3 million,
respectively.
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.
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, 2006. Management certified this fact in its
Sarbanes Oxley Section 302 certifications, which are attached as exhibits to
this 2006 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, 2006 and
2005, and the related consolidated statements of income, shareholder’s equity,
and cash flows for each of the three years in the period ended December 31,
2006. Our audits also included the financial statement schedule listed in the
Index at Item 15. These financial statements and financial statement schedule
are the responsibility of the Company's management. Our responsibility is to
express an opinion on the financial statements and financial statement schedule
based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. 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, 2006 and 2005, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2006, 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, present fairly in all material respects the
information set forth therein.
|
DELOITTE
& TOUCHE LLP
|
|
Indianapolis,
Indiana
|
|
February
16, 2007
|
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
At
December 31,
|
|||||||
|
2006
|
2005
|
||||||
|
ASSETS
|
|||||||
|
Current
Assets
|
|||||||
|
Cash
& cash equivalents
|
$
|
28.5
|
$
|
11.7
|
|||
|
Accounts
receivable - less reserves of $2.5 &
|
|||||||
|
$2.6,
respectively
|
134.8
|
170.7
|
|||||
|
Receivables
due from other Vectren companies
|
0.3
|
2.2
|
|||||
|
Accrued
unbilled revenues
|
121.4
|
212.5
|
|||||
|
Inventories
|
141.9
|
126.2
|
|||||
|
Recoverable
fuel & natural gas costs
|
1.8
|
15.4
|
|||||
|
Prepayments
& other current assets
|
103.2
|
117.2
|
|||||
|
Total
current assets
|
531.9
|
655.9
|
|||||
|
Utility
Plant
|
|||||||
|
Original cost
|
3,820.2
|
3,632.0
|
|||||
|
Less: accumulated depreciation & amortization
|
1,434.7
|
1,380.1
|
|||||
|
Net utility plant
|
2,385.5
|
2,251.9
|
|||||
|
Investments
in unconsolidated affiliates
|
0.2
|
0.2
|
|||||
|
Other
investments
|
21.4
|
21.0
|
|||||
|
Nonutility
property - net
|
163.1
|
160.0
|
|||||
|
Goodwill
- net
|
205.0
|
205.0
|
|||||
|
Regulatory
assets
|
116.8
|
89.9
|
|||||
|
Other
assets
|
16.9
|
7.3
|
|||||
|
TOTAL
ASSETS
|
$
|
3,440.8
|
$
|
3,391.2
|
|||
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,
|
|||||||
|
2006
|
2005
|
||||||
|
LIABILITIES
& SHAREHOLDER'S EQUITY
|
|||||||
|
Current
Liabilities
|
|||||||
|
Accounts
payable
|
$
|
136.2
|
$
|
131.9
|
|||
|
Accounts
payable to affiliated companies
|
68.2
|
140.6
|
|||||
|
Payables
to other Vectren companies
|
25.3
|
29.2
|
|||||
|
Refundable
fuel & natural gas costs
|
35.3
|
7.6
|
|||||
|
Accrued
liabilities
|
115.8
|
130.4
|
|||||
|
Short-term
borrowings
|
270.1
|
226.9
|
|||||
|
Current
maturities of long-term debt
|
6.5
|
-
|
|||||
|
Long-term
debt subject to tender
|
20.0
|
53.7
|
|||||
|
Total
current liabilities
|
677.4
|
720.3
|
|||||
|
Long-Term
Debt - Net of Current Maturities &
|
|||||||
|
Debt
Subject to Tender
|
1,025.3
|
997.8
|
|||||
|
Deferred
Income Taxes & Other Liabilities
|
|||||||
|
Deferred
income taxes
|
282.2
|
275.5
|
|||||
|
Regulatory
liabilities
|
291.1
|
272.9
|
|||||
|
Deferred
credits & other liabilities
|
108.1
|
100.9
|
|||||
|
Total
deferred credits & other liabilities
|
681.4
|
649.3
|
|||||
|
Commitments
& Contingencies (Notes 7 - 10)
|
|||||||
|
Common
Shareholder's Equity
|
|||||||
|
Common
stock (no par value)
|
632.9
|
612.9
|
|||||
|
Retained
earnings
|
422.9
|
406.9
|
|||||
|
Accumulated
other comprehensive income
|
0.9
|
4.0
|
|||||
|
Total
common shareholder's equity
|
1,056.7
|
1,023.8
|
|||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$
|
3,440.8
|
$
|
3,391.2
|
|||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF INCOME
(In
millions)
|
Year
Ended December 31,
|
||||||||||
|
2006
|
|
2005
|
|
2004
|
||||||
|
OPERATING
REVENUES
|
||||||||||
|
Gas
utility
|
$
|
1,232.5
|
$
|
1,359.7
|
$
|
1,126.2
|
||||
|
Electric
utility
|
422.2
|
421.4
|
371.3
|
|||||||
|
Other
|
1.8
|
0.7
|
0.5
|
|||||||
|
Total
operating revenues
|
1,656.5
|
1,781.8
|
1,498.0
|
|||||||
|
OPERATING
EXPENSES
|
||||||||||
|
Cost
of gas sold
|
841.5
|
973.3
|
778.5
|
|||||||
|
Cost
of fuel & purchased power
|
151.5
|
144.1
|
116.8
|
|||||||
|
Other
operating
|
239.0
|
241.3
|
220.4
|
|||||||
|
Depreciation
& amortization
|
151.3
|
141.3
|
127.8
|
|||||||
|
Taxes
other than income taxes
|
64.2
|
65.2
|
58.2
|
|||||||
|
Total
operating expenses
|
1,447.5
|
1,565.2
|
1,301.7
|
|||||||
|
OPERATING
INCOME
|
209.0
|
216.6
|
196.3
|
|||||||
|
OTHER
INCOME
|
||||||||||
|
Other
- net
|
7.6
|
5.9
|
7.1
|
|||||||
|
Equity
in earnings of unconsolidated affiliates
|
-
|
-
|
0.2
|
|||||||
|
Total
other income
|
7.6
|
5.9
|
7.3
|
|||||||
|
Interest
expense
|
77.5
|
69.9
|
67.4
|
|||||||
|
INCOME
BEFORE INCOME TAXES
|
139.1
|
152.6
|
136.2
|
|||||||
|
Income
taxes
|
47.7
|
57.5
|
53.1
|
|||||||
|
NET
INCOME
|
$
|
91.4
|
$
|
95.1
|
$
|
83.1
|
||||
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,
|
||||||||||
|
2006
|
|
2005
|
|
2004
|
|
|||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||
|
Net
income
|
$
|
91.4
|
$
|
95.1
|
$
|
83.1
|
||||
|
Adjustments
to reconcile net income to cash from operating activities:
|
||||||||||
|
Depreciation
& amortization
|
151.3
|
141.3
|
127.8
|
|||||||
|
Deferred
income taxes & investment tax credits
|
(6.4
|
)
|
33.1
|
43.0
|
||||||
|
Expense
portion of pension & postretirement periodic benefit cost
|
4.2
|
4.0
|
4.1
|
|||||||
|
Provision
for uncollectible accounts
|
13.6
|
14.4
|
10.7
|
|||||||
|
Other
non-cash (income) expense - net
|
(2.4
|
)
|
1.3
|
0.5
|
||||||
|
Changes
in working capital accounts:
|
||||||||||
|
Accounts
receivable, including to Vectren companies
|
||||||||||
|
&
accrued unbilled revenue
|
115.3
|
(88.1
|
)
|
(78.0
|
)
|
|||||
|
Inventories
|
(15.7
|
)
|
(68.2
|
)
|
(3.5
|
)
|
||||
|
Recoverable
fuel & natural gas costs
|
41.3
|
3.6
|
8.9
|
|||||||
|
Prepayments
& other current assets
|
16.7
|
23.3
|
(2.9
|
)
|
||||||
|
Accounts
payable, including to Vectren companies
|
||||||||||
|
&
affiliated companies
|
(74.7
|
)
|
100.7
|
37.9
|
||||||
|
Accrued
liabilities
|
(14.2
|
)
|
15.7
|
13.2
|
||||||
|
Changes
in noncurrent assets
|
(27.2
|
)
|
(8.4
|
)
|
(1.9
|
)
|
||||
|
Changes
in noncurrent liabilities
|
(7.1
|
)
|
(2.0
|
)
|
(10.0
|
)
|
||||
|
Net
cash flows from operating activities
|
286.1
|
265.8
|
232.9
|
|||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||
|
Proceeds
from:
|
||||||||||
|
Long-term
debt - net of issuance costs & hedging proceeds
|
92.8
|
150.0
|
32.4
|
|||||||
|
Additional
capital contribution
|
20.0
|
20.0
|
3.1
|
|||||||
|
Requirements
for:
|
||||||||||
|
Dividends
to parent
|
(75.4
|
)
|
(80.7
|
)
|
(80.6
|
)
|
||||
|
Retirement
of long-term debt, including premiums paid
|
(100.0
|
)
|
(49.9
|
)
|
(70.5
|
)
|
||||
|
Redemption
of preferred stock of subsidiary
|
-
|
(0.1
|
)
|
(0.1
|
)
|
|||||
|
Net
change in short-term borrowings, including from other
|
||||||||||
|
Vectren
companies
|
43.2
|
(81.4
|
)
|
123.1
|
||||||
|
Net
cash flows from financing activities
|
(19.4
|
)
|
(42.1
|
)
|
7.4
|
|||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||
|
Proceeds
from other investing activities
|
0.1
|
0.1
|
3.5
|
|||||||
|
Requirements
for capital expenditures, excluding AFUDC equity
|
(250.0
|
)
|
(217.8
|
)
|
(246.2
|
)
|
||||
|
Net
cash flows from investing activities
|
(249.9
|
)
|
(217.7
|
)
|
(242.7
|
)
|
||||
|
Net
(decrease) increase in cash & cash equivalents
|
16.8
|
6.0
|
(2.4
|
)
|
||||||
|
Cash
& cash equivalents at beginning of period
|
11.7
|
5.7
|
8.1
|
|||||||
|
Cash
& cash equivalents at end of period
|
$
|
28.5
|
$
|
11.7
|
$
|
5.7
|
||||
|
Cash
paid during the year for:
|
||||||||||
|
Interest
|
$
|
75.2
|
$
|
65.9
|
$
|
65.0
|
||||
|
Income
taxes
|
49.8
|
43.3
|
6.1
|
|||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(In
millions)
|
|
|
|
|
Accumulated
|
|
|
|
||||||
|
|
|
|
|
|
|
Other
|
|
|
|
||||
|
|
|
Common
|
|
Retained
|
|
Comprehensive
|
|
|
|
||||
|
|
|
Stock
|
|
Earnings
|
|
Income
(Loss)
|
|
Total
|
|||||
|
Balance
at January 1, 2004
|
$ |
589.8
|
$ |
390.0
|
$ |
-
|
$ |
979.8
|
|||||
|
Net
income and comprehensive income
|
83.1
|
83.1
|
|||||||||||
|
Common
stock:
|
|||||||||||||
|
Additional
capital contribution
|
3.1
|
3.1
|
|||||||||||
|
Dividends
|
(80.6
|
)
|
(80.6
|
)
|
|||||||||
|
Balance
at December 31, 2004
|
$
|
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
|
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
|
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
|
|||||
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. (Utility Holdings or the Company), an Indiana
corporation, serves as the intermediate holding company for Vectren
Corporation’s (Vectren) three operating public utilities, Indiana Gas Company,
Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and
the
Ohio operations. Utility Holdings also has assets that provide information
technology and other services to the utilities. Vectren is an energy holding
company headquartered in Evansville, Indiana. Both Vectren and Utility Holdings
were exempt from registration pursuant to Section 3(a) (1) and 3(c) of the
Public Utility Holding Company Act of 1935, which was repealed effective
February 8, 2006 by the Energy Policy Act of 2005 (Energy Act). Both Vectren
and
Utility Holdings are holding companies as defined by the Energy Act.
Indiana
Gas provides energy delivery services to approximately 565,000 natural gas
customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 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, (53% ownership) and Indiana Gas (47% 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)
|
2006
|
|
2005
|
||
|
Gas
in storage – at average cost
|
$
61.3
|
$
63.3
|
|||
|
Materials
& supplies
|
28.0
|
29.9
|
|||
|
Gas
in storage – at LIFO cost
|
26.5
|
18.8
|
|||
|
Fuel
(coal & oil) for electric generation
|
26.0
|
14.1
|
|||
|
Other
|
0.1
|
0.1
|
|||
|
Total
inventories
|
$
141.9
|
$
126.2
|
|||
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, 2006, and 2005, by approximately $79.0 million and $117.0 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, which include
a
cost of removal component, are established through regulatory proceedings and
are applied to all in-service utility plant. The
original
cost of utility plant, together with depreciation rates expressed as a
percentage of original cost, follows:
|
At
and For the Year Ended December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
|
2005
|
|||
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|||
|
Gas
utility plant
|
$
1,956.1
|
3.6%
|
$
1,879.1
|
3.5%
|
|||
|
Electric
utility plant
|
1,685.5
|
3.7%
|
1,611.4
|
3.7%
|
|||
|
Common
utility plant
|
45.2
|
2.6%
|
44.2
|
2.6%
|
|||
|
Construction
work in progress
|
133.4
|
-
|
97.3
|
-
|
|||
|
Total
original cost
|
$
3,820.2
|
$
3,632.0
|
|||||
AFUDC
represents the cost of borrowed and equity funds used for construction purposes,
and is 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)
|
2006
|
|
2005
|
|
2004
|
|||||
|
AFUDC
– borrowed funds
|
$
|
2.6
|
$
|
1.6
|
$
|
1.6
|
||||
|
AFUDC
– equity funds
|
1.5
|
0.3
|
1.6
|
|||||||
|
Total
AFUDC capitalized
|
$
|
4.1
|
$
|
1.9
|
$
|
3.2
|
||||
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 charged against Regulatory
liabilities,
where
the cost of removal obligation is classified in these financial
statements.
Jointly
Owned Plant
SIGECO
and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300
MW
Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the
cost of this unit at December 31, 2006 is $63.2 million with accumulated
depreciation totaling $43.5 million. 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)
|
2006
|
|
2005
|
||||
|
Computer
hardware & software
|
$
|
105.4
|
$
|
103.3
|
|||
|
Land
& buildings
|
44.9
|
43.5
|
|||||
|
All
other
|
12.8
|
13.2
|
|||||
|
Nonutility
property - net
|
$
|
163.1
|
$
|
160.0
|
|||
The
depreciation of nonutility property is charged against income over its estimated
useful life (ranging from 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 $113.7 million and $92.7 million as
of
December 31, 2006, and 2005, respectively. For the years ended December 31,
2006, 2005 and 2004, the Company capitalized interest totaling $0.7 million,
$0.6 million, and $1.4 million, respectively, on nonutility plant construction
projects.
| F. |
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.
| G. |
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, 2006,
no
goodwill impairments have been recorded. All of the Company’s goodwill is
included in the Gas Utility Services operating segment.
| H. |
Asset
Retirement Obligations
|
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. Over time, 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.
Asset
retirement obligations total $18.3 million at December 31, 2006 and $17.3
million at December 31, 2005, and are included in Other
Liabilities.
During
2006, the Company recorded accretion of $1.0 million. In 2005, the Company
recorded accretion of $0.1 million and recorded additional liabilities of $16.0
million, related to the adoption of FASB Interpretation No. 47.
| I. |
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)
|
2006
|
|
2005
|
||||
|
Future
amounts recoverable from ratepayers:
|
|||||||
|
Income
taxes
|
$
|
13.3
|
$
|
11.1
|
|||
|
Asset
retirement obligations & other
|
5.2
|
1.7
|
|||||
|
18.5
|
12.8
|
||||||
|
Amounts
deferred for future recovery:
|
|||||||
|
Demand
side management programs
|
27.7
|
26.7
|
|||||
|
MISO-related
costs
|
17.1
|
9.4
|
|||||
|
Cost
recovery riders & other
|
4.7
|
2.5
|
|||||
|
49.5
|
38.6
|
||||||
|
Amounts
currently recovered through base rates:
|
|||||||
|
Unamortized
debt issue costs
|
23.1
|
20.2
|
|||||
|
Premiums
paid to reacquire debt
|
6.0
|
6.5
|
|||||
|
Demand
side management programs & other
|
3.3
|
4.5
|
|||||
|
32.4
|
31.2
|
||||||
|
Amounts
currently recovered through tracking mechanisms:
|
|||||||
|
Ohio
authorized trackers
|
10.3
|
5.6
|
|||||
|
Indiana
authorized trackers
|
6.1
|
1.7
|
|||||
|
16.4
|
7.3
|
||||||
|
Total
regulatory assets
|
$
|
116.8
|
$
|
89.9
|
|||
Of
the
$32.4 million currently being recovered through base rates charged to customers,
$1.5 million is earning a return. The weighted average recovery period of
regulatory assets currently being recovered is 14.4 years. The Company has
rate
orders for all deferred costs not yet in rates and therefore believes that
future recovery is probable.
Regulatory
liabilities
consist
of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Advances
from rate-payers related to:
|
|||||||
|
Cost
of removal
|
$
|
270.6
|
$
|
251.4
|
|||
|
Asset
retirement obligations
|
11.3
|
11.6
|
|||||
|
281.9
|
263.0
|
||||||
|
Amounts
currently amortizing related to:
|
|||||||
|
Interest
rate hedging proceeds
|
6.1
|
6.8
|
|||||
|
Amounts
deferred for future settlement related to:
|
|||||||
|
MISO-related
costs
|
3.1
|
3.1
|
|||||
|
Total
regulatory liabilities
|
$
|
291.1
|
$
|
272.9
|
|||
Cost
of Removal
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).
Asset
Retirement Obligations
A
portion
of removal costs related to interim retirements of gas utility pipeline and
utility poles, certain asbestos-related issues, and reclamation activities
meet
the definition of an asset retirement obligation (ARO). The regulatory liability
above represents a timing difference between cost recognition described in
SFAS
143, and cost recognition established in regulatory proceedings for these
obligations.
| J. |
Comprehensive
Income
|
Comprehensive
income is a measure of all changes in equity that result from the
non-shareholder transactions. This information is reported in the Consolidated
Statements of Common Shareholders' Equity. A summary of the components of and
changes in Accumulated
other comprehensive income
for the
past three years follows:
|
2004
|
|
2005
|
|
2006
|
||||||||||||||||||
|
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
|
||||||||||||||
|
Deferred
income taxes
|
-
|
-
|
-
|
(2.7
|
)
|
(2.7
|
)
|
2.2
|
(0.5
|
)
|
||||||||||||
|
Accumulated
other comprehensive income (loss)
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
4.0
|
$
|
4.0
|
$
|
(3.1
|
)
|
$
|
0.9
|
|||||||