Attached files
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
|
ý
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the fiscal year ended December 31, 2009
OR
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
transition period from __________________ to
________________________
Commission
file number: 1-16739
|
VECTREN
UTILITY HOLDINGS, INC.
|
(Exact
name of registrant as specified in its charter)
|
INDIANA
|
35-2104850
|
|
|
(State
or other jurisdiction of incorporation or organization)
|
(IRS
Employer Identification No.)
|
|
|
One
Vectren Square
|
47708
|
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant's
telephone number, including area code: 812-491-4000
Securities
registered pursuant to Section 12(b) of the Act:
|
Title
of each class
|
Name
of each exchange on which registered
|
|
|
Vectren Utility 6.10% SR NTS
12/1/2035
|
New
York Stock Exchange
|
Securities
registered pursuant to Section 12(g) of the Act:
|
Title
of each class
|
Name
of each exchange on which registered
|
|
|
Common – Without
Par
|
None
|
Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act.
*Yes ý No□
*Utility Holdings is a majority
owned subsidiary of a well-known seasoned issuer, and well-known seasoned issuer
status depends in part on the type of security being registered by the
majority-owned subsidiary.
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes □
No ý
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes ý No □
Indicate by check mark whether the
registrant has submitted electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and posted pursuant to
Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter
period that the registrant was required to submit and post such
files).
□ Yes □ No
Indicate by check mark if disclosure of
delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. □
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer □ Accelerated filer □
Non-accelerated
filer ý Smaller
reporting company □
(Do not
check if a smaller reporting company)
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
The
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of June
30, 2009, 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.
|
Common Stock - Without Par
Value
|
10
|
February 28, 2010
|
|
Class
|
Number
of Shares
|
Date
|
Omission
of Information by Certain Wholly Owned Subsidiaries
The
Registrant is a wholly owned subsidiary of Vectren Corporation and meets the
conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and
is therefore filing with the reduced disclosure format contemplated
thereby.
Definitions
|
AFUDC: allowance
for funds used during construction
|
MISO:
Midwest Independent System Operator
|
|
ASC: Accounting
Standards Codification
|
MW: megawatts
|
|
BTU
/ MMBTU: British thermal units / millions of BTU
|
MWh
/ GWh: megawatt hours / thousands of megawatt hours (gigawatt
hours)
|
|
FASB: Financial
Accounting Standards Board
|
NERC: North
American Electric Reliability Corporation
|
|
FERC: Federal
Energy Regulatory Commission
|
OCC: Ohio
Office of the Consumer Counselor
|
|
IDEM: Indiana
Department of Environmental Management
|
OUCC: Indiana
Office of the Utility Consumer Counselor
|
|
IRC: Internal
Revenue Code
|
PUCO: Public
Utilities Commission of Ohio
|
|
IURC: Indiana
Utility Regulatory Commission
|
USEPA: United
States Environmental Protection Agency
|
|
MCF
/ BCF: thousands / billions of cubic feet
|
Throughput: combined
gas sales and gas transportation volumes
|
|
MDth
/ MMDth: thousands / millions of dekatherms
|
Access
to Information
Vectren
Corporation makes available all SEC filings and recent annual reports, including
those of Vectren Utility Holdings, Inc., free of charge through its website at
www.vectren.com
as soon as reasonably practicable after electronically filing or furnishing the
reports to the SEC, or by request, directed to Investor Relations at the mailing
address, phone number, or email address that follows:
|
Mailing
Address:
One
Vectren Square
Evansville,
Indiana 47708
|
Phone
Number:
(812)
491-4000
|
Investor
Relations Contact:
Steven
M. Schein
Vice
President, Investor Relations
sschein@vectren.com
|
||
Table
of Contents
|
Item
|
Page
|
|||||
|
Number
|
Number
|
|||||
|
Part
I
|
||||||
|
4
|
Reserved
|
15
|
||||
|
Part
II
|
||||||
|
|
||||||
|
Part
III
|
||||||
|
|
||||||
|
Part
IV
|
||||||
|
(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.
|
PART
I
ITEM 1. BUSINESS
Description of the
Business
Vectren
Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana
corporation, was formed on March 31, 2000 to serve as the intermediate holding
company for Vectren Corporation’s (Vectren) three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North),
Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the
Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has
other assets that provide information technology and other services to the three
utilities. Vectren, an Indiana corporation, is an energy holding
company headquartered in Evansville, Indiana and was organized on June 10,
1999. Both Vectren and Utility Holdings are holding companies as
defined by the Energy Policy Act of 2005 (Energy Act).
Indiana
Gas provides energy delivery services to over 567,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 111,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation assets to serve its electric
customers and optimizes those assets in the wholesale power
market. Indiana Gas and SIGECO generally do business as Vectren
Energy Delivery of Indiana. The Ohio operations provide energy
delivery services to approximately 315,000 natural gas customers located near
Dayton in west central Ohio. The Ohio operations are owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly
owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47
percent ownership). The Ohio operations generally do business as
Vectren Energy Delivery of Ohio.
Narrative Description of the
Business
The
Company has regulated operations and other operations that provide information
technology and other support services to those regulated
operations. The Company segregates its regulated operations into a
Gas Utility Services operating segment and an Electric Utility Services
operating segment. The Gas Utility Services segment includes the
operations of Indiana Gas, the Ohio operations, and SIGECO’s natural gas
distribution business and provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and to west central
Ohio. The Electric Utility Services segment includes the operations
of SIGECO’s electric transmission and distribution services, which provides
electric distribution services primarily to southwestern Indiana, and the
Company’s power generating and wholesale power operations. In total,
these regulated operations supply natural gas and/or electricity to over one
million customers. The Utility Group’s other operations are not
significant.
At
December 31, 2009, the Company had $3.8 billion in total assets, with $2.1
billion (55 percent) attributed to Gas Utility Services, $1.6 billion (42
percent) attributed to Electric Utility Services, and $0.1 billion (3 percent)
attributed to Other Operations. Net income for the year ended
December 31, 2009, was $107.4 million, with $50.2 million attributed to Gas
Utility Services, $48.3 million attributed to Electric Utility Services, and
$8.9 million attributed to Other Operations. Net income for the year
ended December 31, 2008, was $111.1 million. For further information
regarding the activities and assets of operating segments, refer to Note 11 in
the Company’s consolidated financial statements included under “Item 8 Financial
Statements and Supplementary Data.”
Following
is a more detailed description of the Gas Utility Services and Electric Utility
Services operating segments. The Company’s Other Operations are not
significant.
Gas
Utility Services
At
December 31, 2009, the Company supplied natural gas service to approximately
993,100 Indiana and Ohio customers, including 907,500 residential, 84,000
commercial, and 1,600 industrial and other contract
customers. Average gas utility customers served were approximately
981,300 in 2009 and 986,700 in both 2008 and 2007.
The
Company’s service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served
include automotive assembly, parts and accessories, feed, flour and grain
processing, metal castings, aluminum products, appliance manufacturing,
polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical
equipment, metal specialties, glass, steel finishing, pharmaceutical and
nutritional products, gasoline and oil products, ethanol and coal
mining. The largest Indiana communities served are Evansville,
Bloomington, Terre Haute, and suburban areas surrounding Indianapolis and
Indiana counties near Louisville, Kentucky. The largest community
served outside of Indiana is Dayton, Ohio.
Revenues
The
Company receives gas revenues by selling gas directly to customers at approved
rates or by transporting gas through its pipelines at approved rates to
customers that have purchased gas directly from other producers, brokers, or
marketers. Total throughput was 184.5 MMDth for the year ended
December 31, 2009. Gas sold and transported to residential and
commercial customers was 106.5 MMDth representing 58 percent of
throughput. Gas transported or sold to industrial and other contract
customers was 78.0 MMDth representing 42 percent of throughput. Rates
for transporting gas generally provide for the same margins earned by selling
gas under applicable sales tariffs.
For the
year ended December 31, 2009, gas utility revenues were approximately $1,066.0
million, of which residential customers accounted for 68 percent and commercial
26 percent. Industrial and other contract customers account for only 6 percent
of revenues due to the high number of transportation customers in that customer
class.
Availability
of Natural Gas
The
volume of gas sold is seasonal and affected by variations in weather
conditions. To mitigate seasonal demand, the Company’s Indiana gas
utilities have storage capacity at seven active underground gas storage fields
and six liquefied petroleum air-gas manufacturing
plants. Periodically, purchased natural gas is injected into
storage. The injected gas is then available to supplement contracted
and manufactured volumes during periods of peak requirements. The
volumes of gas per day that can be delivered during peak demand periods for each
utility are located in “Item 2 Properties.”
Natural Gas Purchasing
Activity in Indiana
The
Indiana utilities also contract with its affiliate, ProLiance Holdings, LLC
(ProLiance), to ensure availability of gas. ProLiance is an
unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens
Energy Group (Citizens). (See the discussion of Energy Marketing
& Services below and Note 5 in the Company’s Consolidated Financial
Statements included in “Item 8 Financial Statements and Supplementary Data”
regarding transactions with ProLiance). The Company also prepays
ProLiance for natural gas delivery services during the seven months prior to the
peak heating season in lieu of maintaining gas storage. Vectren
received regulatory approval on April 25, 2006 from the IURC for ProLiance to
continue to provide natural gas supply services to the Company’s Indiana
utilities through March 2011.
Natural Gas Purchasing
Activity in Ohio
As a
result of a June 2005 PUCO order, the Company established an annual bidding
process for VEDO’s gas supply and portfolio administration
services. From November 1, 2005 through September 30, 2008, the
Company used a third party provider for these services. Prior to
October 31, 2005, ProLiance also supplied natural gas to Utility Holdings’ Ohio
operations.
On April
30, 2008, the PUCO issued an order adopting a stipulation involving the Company,
the OCC, and other interveners. The order approved the first
two phases of a three phase plan to exit the merchant function in the
Company’s Ohio service territory.
The
initial phase of the plan was implemented on October 1, 2008 and continues
through March 31, 2010. During the initial phase, wholesale suppliers that
were winning bidders in a PUCO approved auction provide the gas commodity to
VEDO for resale to its residential and general service customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. On October 1, 2008, the Company transferred its natural gas
inventory at book value to the winning bidders, receiving proceeds of
approximately $107 million, and now purchases natural gas from those suppliers
(one of which is Vectren Retail, LLC, a wholly owned subsidiary of Vectren)
essentially on demand. This method of purchasing gas eliminated the need
for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits.
The
second phase of the exit process begins on April 1, 2010, during which the
Company will no longer sell natural gas directly to these
customers. Rather, state-certified Competitive Retail Natural Gas
Suppliers, that are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers for 12 months at
auction-determined standard pricing. That auction was conducted on
January 12, 2010, and the auction results were approved by the PUCO on January
13. The plan approved by the PUCO requires that the Company conduct at
least two auctions during this phase. As such, the Company will conduct
another auction in advance of the second 12-month term, which will commence on
April 1, 2011. Consistent with current practice, customers will
continue to receive one bill for the delivery of natural gas
service.
In the
last phase, which was not approved in the April 2008 order, it is contemplated
that all of the Company’s Ohio residential and general service customers will
choose their commodity supplier from state-certified Competitive Retail Natural
Gas Suppliers in a competitive market.
The PUCO
has also provided for an Exit Transition Cost rider for the first two phases of
the transition, which allows the Company to recover costs associated with the
transition, and it is anticipated this rider will remain in effect throughout
the entire transition. Since the cost of gas is currently passed
through to customers during phase one and two through a PUCO approved recovery
mechanism, the impact of exiting the merchant function should not have a
material impact on Company earnings or financial condition.
Total Natural Gas Purchased
Volumes
In 2009,
Utility Holdings purchased 97,682 MDth volumes of gas at an average cost of
$5.97 per Dth, of which approximately 76 percent was purchased from ProLiance, 4
percent was purchased from Vectren Retail, LLC (d/b/a Vectren Source), as
discussed above, and 20 percent was purchased from third party
providers. The average cost of gas per Dth purchased for the previous
four years was $9.61 in 2008, $8.14 in 2007, $8.64 in 2006, and $9.05 in
2005.
Electric
Utility Services
At
December 31, 2009, the Company supplied electric service to approximately
141,400 Indiana customers, including approximately 122,900 residential, 18,400
commercial, and 100 industrial and other customers. Average electric
utility customers served were approximately 140,900 in 2009; 141,100 in 2008;
and 140,800 in 2007.
The
principal industries served include polycarbonate resin (Lexan®) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, ethanol, and
coal mining.
Revenues
For the
year ended December 31, 2009, retail electricity sales totaled 5,039.7 GWh,
resulting in revenues of approximately $493.2 million. Residential
customers accounted for 37 percent of 2009 revenues; commercial 28 percent;
industrial 33 percent, and other 2 percent. In addition, in 2009 the
Company sold 603.6 GWh through wholesale activities principally to the
MISO. Wholesale revenues, including transmission-related revenue,
totaled $35.4 million in 2009.
System
Load
Total
load for each of the years 2005 through 2009 at the time of the system summer
peak, and the related reserve margin, is presented below in MW. The
peak loads in 2009 reflect the current weak industrial demand and mild
weather.
|
Date
of summer peak load
|
6/22/2009
|
7/21/2008
|
8/08/2007
|
8/10/2006
|
7/25/2005
|
|||||
|
Total
load at peak (1)
|
1,143
|
1,242
|
1,341
|
1,325
|
1,315
|
|||||
|
Generating
capability
|
1,295
|
1,295
|
1,295
|
1,351
|
1,351
|
|||||
|
Firm
purchase supply
|
136
|
135
|
130
|
107
|
107
|
|||||
|
Interruptible
contracts & direct load control
|
62
|
62
|
62
|
62
|
76
|
|||||
|
Total
power supply capacity
|
1,493
|
1,492
|
1,487
|
1,520
|
1,534
|
|||||
|
Reserve
margin at peak
|
31%
|
20%
|
11%
|
15%
|
17%
|
|||||
|
(1)
|
The
total load at peak is increased 25 MW in 2007-2005 from the total load
actually experienced. The additional 25 MW represents load that
would have been incurred if the Summer Cycler program had not been
activated. The 25 MW is also included in the interruptible
contract portion of the Company’s total power supply capacity in those
years. On the date of peak in 2008 and 2009 the Summer Cycler
program was not activated.
|
The
winter peak load for the 2008-2009 season of approximately 883 MW occurred on
January 15, 2009. The prior year winter peak load was approximately
960 MW, occurring on January 25, 2008.
Generating
Capability
Installed
generating capacity as of December 31, 2009, was rated at 1,298
MW. Coal-fired generating units provide 1,000 MW of capacity, natural
gas or oil-fired turbines used for peaking or emergency conditions provide 295
MW, and in 2009 SIGECO purchased a landfill gas electric generation project
which provides 3 MW. Electric generation for 2009 was fueled by coal
(98 percent) and natural gas (2 percent). Oil was used only for
testing of gas/oil-fired peaking units. The Company generated
approximately 4,657 GWh in 2009. Further information about the
Company’s owned generation is included in Item 2 Properties.
There are
substantial coal reserves in the southern Indiana area, and coal for coal-fired
generating stations has been supplied from operators of nearby coal mines,
including coal mines in Indiana owned by Vectren Fuels, Inc. (Vectren Fuels), a
wholly owned subsidiary of the Company. Approximately 2.8 million
tons were purchased for generating electricity during 2009, of which
approximately 86 percent was supplied by Vectren Fuels from its mines and third
party purchases. The average cost of coal paid by the utility in
generating electric energy for the years 2005 through 2009 follows:
|
Year
Ended December 31,
|
||||||||||||||||||||
|
Average
Delivered
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
|
Cost
per Ton
|
$ | 61.67 | $ | 42.50 | $ | 40.23 | $ | 37.51 | $ | 30.27 | ||||||||||
|
Cost
per MWh
|
30.09 | 20.84 | 19.78 | 18.44 | 14.94 | |||||||||||||||
As of January 1, 2009, SIGECO purchases coal from Vectren Fuels under new coal purchase agreements. The term of these coal purchase agreements continues to December 31, 2014, with prices specified originally ranging from two to four years. New pricing reflects Illinois Basin market prices in effect when the contracts were executed and have resulted in higher costs compared to prior years.
The
utility purchased approximately 13.3 percent less coal in 2009 compared to
2008. Due to contractual obligations, its year end coal inventory
rose to approximately 1.1 million tons, compared to 0.5 million tons at the end
of 2008.
Firm
Purchase Supply
The
Company has a 1.5 percent interest in the Ohio Valley Electric Corporation
(OVEC). OVEC is comprised of several electric utility companies,
including SIGECO, and supplies power requirements to the United States
Department of Energy’s (DOE) uranium enrichment plant near Portsmouth,
Ohio. The participating companies can receive from OVEC, and are
obligated to pay for, any available power in excess of the DOE contract
demand. At the present time, the DOE contract demand is essentially
zero. The Company’s 1.5 percent interest in OVEC makes available
approximately 30 MW of capacity. The Company purchased approximately
211 GWh from OVEC in 2009.
The
Company had a capacity contract with Duke Energy Marketing America, LLC to
purchase as much as 100 MW at any time from a power plant located in Vermillion
County, Indiana. The contract expired on December 31, 2009 and was
not renewed. The Company purchased insignificant amounts under this
contract in 2009.
The
Company executed a capacity contract with Benton County Wind Farm, LLC on April
15, 2008 to purchase as much as 30 MW from a wind farm located in Benton County,
Indiana, with the approval of the IURC. The contract expires in
2029. In 2009, the Company purchased approximately 91 GWh under this
contract; however, none was purchased at the time of peak load on June 22,
2009.
In
December 2009, the Company executed a 20 year power
purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50
MW of energy from a wind farm located in Benton and Tippecanoe Counties in
Indiana, with the approval of the IURC. The Company purchased
insignificant amounts under this contract in 2009.
Other
Power Purchases
The
Company also purchases power as needed principally from the MISO to supplement
its generation and firm purchase supply in periods of peak
demand. Volumes purchased principally from the MISO in 2009 totaled
855 GWh.
Midwest
Independent System Operator (MISO) Capacity Purchase
In May
2008, the Company executed a MISO capacity purchase from Sempra Energy Trading,
LLC to purchase 100MW of name plate capacity from its generating facility in
Dearborn, Michigan. The term of the contract begins January 1, 2010
and continues through December 31, 2012.
Interconnections
The
Company has interconnections with Louisville Gas and Electric Company, Duke
Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier
Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and
the City of Jasper, Indiana, providing the historic ability to simultaneously
interchange approximately 600 MW. However, the ability of the Company
to effectively utilize the electric transmission grid in order to achieve its
desired import/export capability has been, and may continue to be, impacted as a
result of the ongoing changes in the operation of the Midwestern transmission
grid. The Company, as a member of the MISO, has turned over
operational control of the interchange facilities and its own transmission
assets, like many other Midwestern electric utilities, to MISO. See
“Item 7 Management’s Discussion and Analysis of Results of Operations and
Financial Condition” regarding the Company’s participation in MISO.
Competition
The
utility industry has undergone structural change for several years, resulting in
increasing competitive pressures faced by electric and gas utility
companies. Currently, several states have passed legislation allowing
electricity customers to choose their electricity supplier in a competitive
electricity market and several other states have considered such
legislation. At the present time, Indiana has not adopted such
legislation. Ohio regulation allows gas customers to choose their
commodity supplier. The Company implemented a choice program for its
gas customers in Ohio in January 2003. At December 31, 2009, over
117,000 customers in Vectren’s Ohio service territory purchase natural gas from
a supplier other than VEDO. Margin earned for transporting natural
gas to those customers, who have purchased natural gas from another supplier,
are generally the same as those earned by selling gas under Ohio
tariffs. Indiana has not adopted any regulation requiring gas choice;
however, the Company operates under approved tariffs permitting certain
industrial and commercial large volume customers to choose their commodity
supplier.
Regulatory
and Environmental Matters
See “Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s regulatory environment and environmental
matters.
Personnel
As of
December 31, 2009, the Company and its consolidated subsidiaries had 1,600
employees, of which 800 are subject to collective bargaining
arrangements.
In
October 2009, the Company’s existing agreement expired with Local 175 of the
Utility Workers Union of America. Employees continue to work without
a contractual agreement and continue the negotiation process.
In
December 2008, the Company reached a three-year labor agreement, ending December
1, 2011 with Local 1393 of the International Brotherhood of Electrical Workers
and United Steelworkers of America Locals 12213 and 7441.
In July
2007, the Company reached a three-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2010.
ITEM 1A. RISK FACTORS
Investors
should consider carefully the following factors that could cause the Company’s
operating results and financial condition to be materially adversely
affected. New risks may emerge at any time, and the Company cannot
predict those risks or estimate the extent to which they may affect the
Company’s businesses or financial performance.
Utility
Holdings is a holding company and its assets consist primarily of investments in
its subsidiaries.
The
ability of Utility Holdings to receive dividends and repay indebtedness depends
on the earnings, financial condition, capital requirements and cash flow of its
subsidiaries, SIGECO, Indiana Gas, and VEDO and the distribution or other
payment of earnings from those entities to Utility Holdings. Should the
earnings, financial condition, capital requirements or cash flow of, or legal
requirements applicable to, them restrict their ability to pay dividends or make
other payments to Utility Holdings, its ability to pay dividends to its parent
could be limited. Utility Holdings’ results of operations, future
growth and earnings and dividend goals also will depend on the performance of
its subsidiaries. Additionally, certain of the Company’s lending
arrangements contain restrictive covenants, including the maintenance of a total
debt to total capitalization ratio, which could limit its ability to pay
dividends.
Continued
deterioration in general economic conditions may have adverse
impacts.
The
current economic environment is challenging and uncertain. The
consequences of the recent recession, and despite the beginning recovery, may
continue to result in a lower level of economic activity and uncertainty
regarding energy prices and the capital and commodity
markets. Further, the risks associated with industries in which the
Company operates and serves become more acute in periods of a slowing economy or
slow growth. Economic declines may continue to be accompanied by a
decrease in demand for natural gas and electricity. The recent
recession may continue to have some negative impact on both gas and electric
large customers and wholesale power sales. This impact may
continue to include tempered growth, significant conservation measures, and
perhaps even further plant closures or bankruptcies. Deteriorating
economic conditions may also continue to lead to further reductions in
residential and commercial customer counts, lower Company revenues, and
increasing coal inventories. It is also possible that the recent
recession could continue and further affect costs including pension costs,
interest costs, and uncollectible accounts expense.
Utility
Holdings’ gas and electric utility sales are concentrated in the
Midwest.
The
operations of the Company’s regulated utilities are concentrated in central and
southern Indiana and west central Ohio and are therefore impacted by changes in
the Midwest economy in general and changes in particular industries concentrated
in the Midwest. These industries include automotive assembly, parts
and accessories, feed, flour and grain processing, metal castings, aluminum
products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic
products, gypsum products, electrical equipment, metal specialties, glass, steel
finishing, pharmaceutical and nutritional products, gasoline and oil products,
ethanol and coal mining. While no one industrial customer comprises
10 percent of consolidated revenues, the top five industrial electric customers
comprise approximately 12 percent of electric utility margin, and therefore any
significant decline in their collective revenues could adversely impact
operating results.
Current
financial market volatility could have adverse impacts.
The
capital and credit markets have been experiencing volatility and
disruption. If the level of market disruption and volatility worsen,
there can be no assurance that the Company will not experience adverse effects,
which may be material. These effects may include, but are not limited
to, difficulties in accessing the debt capital markets and the commercial paper
market, increased borrowing costs associated with current debt obligations,
higher interest rates in future financings, and a smaller potential pool of
investors and funding sources. Finally, there is no assurance the
Company’s parent, Vectren, will have access to the equity capital markets to
obtain financing when necessary or desirable.
A
downgrade (or negative outlook) in or withdrawal of Utility Holdings’ credit
ratings could negatively affect its ability to access capital and its
cost.
The
following table shows the current ratings assigned to certain outstanding debt
by Moody’s and Standard & Poor’s:
|
Current
Rating
|
||
|
Standard
|
||
|
Moody’s
|
&
Poor’s
|
|
|
Utility
Holdings and Indiana Gas senior unsecured debt
|
Baa1
|
A-
|
|
Utility
Holdings commercial paper program
|
P-2
|
A-2
|
|
SIGECO’s senior
secured debt
|
A-2
|
A
|
The
current outlook of both Standard and Poor’s and Moody’s is stable and both
categorize the ratings of the above securities as investment grade. A
security rating is not a recommendation to buy, sell, or hold
securities. The rating is subject to revision or withdrawal at any
time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade
rating is BBB- and Baa3, respectively.
Utility
Holdings may be required to obtain additional permanent financing (1) to fund
its capital expenditures, investments and debt security redemptions and
maturities and (2) to further strengthen its capital structure and the capital
structures of its subsidiaries. If the rating agencies downgrade the
Company’s credit ratings, particularly below investment grade, or initiate
negative outlooks thereon, or withdraw Utility Holdings’ ratings or, in each
case, the ratings of its subsidiaries, it may significantly limit Utility
Holdings’ access to the debt capital markets and the commercial paper market,
and the Company’s borrowing costs would increase. In addition,
Utility Holdings would likely be required to pay a higher interest rate in
future financings, and its potential pool of investors and funding sources would
likely decrease. Finally, there is no assurance that the Company’s
parent, Vectren, will have access to the equity capital markets to obtain
financing when necessary or desirable.
Utility
Holdings operates in an increasingly competitive industry, which may affect its
future earnings.
The
utility industry has been undergoing structural change for several years,
resulting in increasing competitive pressure faced by electric and gas utility
companies. Increased competition may create greater risks to the
stability of Vectren’s earnings generally and may in the future reduce its
earnings from retail electric and gas sales. Currently, several
states, including Ohio, have passed legislation that allows customers to choose
their electricity supplier in a competitive market. Indiana has not
enacted such legislation. Ohio regulation also provides for choice of
commodity providers for all gas customers. In 2003, the Company
implemented this choice for its gas customers in Ohio and is currently in the
first of the three phase process to exit the merchant function in its Ohio
service territory. The state of Indiana has not adopted any
regulation requiring gas choice in the Company’s Indiana service territories;
however, the Company operates under approved tariffs permitting certain
industrial and commercial large volume customers to choose their commodity
supplier. Utility Holdings cannot provide any assurance that
increased competition or other changes in legislation, regulation or policies
will not have a material adverse effect on its business, financial condition or
results of operations.
A
significant portion of Utility Holdings electric utility sales are space heating
and cooling. Accordingly, its operating results may fluctuate with
variability of weather.
Utility
Holdings’ electric utility sales are sensitive to variations in weather
conditions. The Company forecasts utility sales on the basis of
normal weather. Since Vectren does not have a weather-normalization
mechanism for its electric operations, significant variations from normal
weather could have a material impact on its earnings. However, the
impact of weather on the gas operations in the Company’s Indiana territories has
been significantly mitigated through the implementation in 2005 of a normal
temperature adjustment mechanism. Additionally, the implementation of
a straight fixed variable rate design over a two year period per a January 2009
PUCO order mitigates most weather risk related to Ohio residential gas
sales.
Risks
related to the regulation of Utility Holdings’ utility businesses, including
environmental regulation, could affect the rates the Company charges its
customers, its costs and its profitability.
Utility
Holdings’ businesses are subject to regulation by federal, state, and local
regulatory authorities and are exposed to public policy decisions that may
negatively impact the Company’s earnings. In particular, Utility
Holdings is subject to regulation by the FERC, the NERC, the USEPA, the IURC,
and the PUCO. These authorities regulate many aspects of its
transmission and distribution operations, including construction and maintenance
of facilities, operations, and safety, and its gas marketing operations
involving title passage, reliability standards, and future
adequacy. In addition, these regulatory agencies approve its
utility-related debt and equity issuances, regulate the rates that the Company
can charge customers, the rate of return that Utility Holdings’ utilities are
authorized to earn, and its ability to timely recover gas and fuel
costs. Further, there are consumer advocates and other parties which
may intervene in regulatory proceedings and affect regulatory
outcomes. The Company’s ability to obtain rate increases to maintain
its current authorized rates of return depends upon regulatory discretion, and
there can be no assurance that Vectren will be able to obtain rate increases or
rate supplements or earn its current authorized rates of return.
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 in
connection with spills, releases, and emissions of various substances in the
environment. Such emissions from electric generating facilities
include particulate matter, sulfur dioxide (SO2), nitrogen
oxide (NOx), and mercury, among others.
Environmental
legislation also requires that facilities, sites, and other properties
associated with the Company’s operations be operated, maintained, abandoned, and
reclaimed to the satisfaction of applicable regulatory
authorities. The Company’s current costs to comply with these laws
and regulations are significant to its results of operations and financial
condition. In addition, claims against the Company under
environmental laws and regulations could result in material costs and
liabilities. With the trend toward stricter standards, greater
regulation, more extensive permit requirements and an increase in the number and
types of assets operated by Utility Holdings subject to environmental
regulation, its investment in environmentally compliant equipment, and the costs
associated with operating that equipment, have increased and are expected to
increase in the future.
Climate
change regulation could negatively impact operations.
There are
proposals to address global climate change that would regulate carbon dioxide
(CO2)
and other greenhouse gases and other proposals that would mandate an investment
in renewable energy sources. Any future legislative or regulatory
actions taken to address global climate change or mandate renewable energy
sources could substantially affect both the costs and operating characteristics
of the Company’s fossil fuel generating plants and natural gas distribution
businesses. Further, any legislation would likely impact the
Company’s generation resource planning decisions. At this time and in the
absence of final legislation, compliance costs and other effects associated with
reductions in greenhouse gas emissions or obtaining renewable energy sources
remain uncertain. The Company has gathered preliminary estimates of the
costs to comply with a cap and trade approach to controlling greenhouse gas
emissions. A preliminary investigation demonstrated costs to comply
would be significant, first with regard to operating expenses for the purchase
of allowances, and later for capital expenditures as technology becomes
available to control greenhouse gas emissions. However, these
compliance cost estimates are based on highly uncertain assumptions, including
allowance prices and energy efficiency targets.
Any
additional expenses or capital incurred by the Company, as it relates to
complying with greenhouse gas emissions regulation or other environmental
regulations, are expected to be borne by the customers in its service
territories through increased rates. Increased rates have an impact
on the economic health of the communities served. New
regulations could also negatively impact industries in the Company’s service
territory.
The
Company is exposed to physical and financial risks related to the uncertainty of
climate change.
A
changing climate creates uncertainty and could result in broad changes to the
Company’s service territories. These impacts could include, but are
not limited to, population shifts; changes in the level of annual rainfall;
changes in the weather; and changes to the frequency and severity of weather
events such as thunderstorms, wind, tornadoes, and ice storms that can damage
infrastructure. Such changes could impact the Company in a number of
ways including the number and/or type of customers in the Company’s service
territories; the demand for energy resulting in the need for additional
investment in generation assets or the need to retire current infrastructure
that is no longer required; an increase to the cost of providing service; and an
increase in the likelihood of capital expenditures to replace damaged
infrastructure.
To the
extent climate change impacts a region’s economic health, it may also impact the
Company’s revenues, costs, and capital structure and thus the need for changes
to rates charged to regulated customers. Rate changes themselves can
impact the economic health of the communities served and may in turn adversely
affect the Company’s operating results.
From
time to time, Utility Holdings is subject to material litigation and regulatory
proceedings.
From time
to time, the Company, as well as its equity investees such as ProLiance, may be
subject to material litigation and regulatory proceedings including matters
involving compliance with state and federal laws, regulations or other
matters. There can be no assurance that the outcome of these matters
will not have a material adverse effect on Utility Holdings’ business,
prospects, results of operations, or financial condition.
Utility
Holdings’ electric
operations are subject to various risks.
The
Company’s electric generating facilities are subject to operational risks that
could result in unscheduled plant outages, unanticipated operation and
maintenance expenses and increased power purchase costs. Such
operational risks can arise from circumstances such as facility shutdowns due to
equipment failure or operator error; interruption of fuel supply or increased
prices of fuel as contracts expire; disruptions in the delivery of electricity;
inability to comply with regulatory or permit requirements; labor disputes; and
natural disasters.
The
impact of MISO participation is uncertain.
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
MISO. The MISO serves the electrical transmission needs of much of the
Midwest and maintains operational control over SIGECO’s electric transmission
facilities as well as that of other Midwest utilities.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO provides bid-based regulation and contingency operating reserve markets
which began on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM.
The need
to expend capital for improvements to the regional transmission system, both to
SIGECO’s facilities as well as to those facilities of adjacent utilities, over
the next several years is expected to be significant. The Company
timely recovers its investment in certain new electric transmission projects
that benefit the MISO infrastructure at a FERC approved rate of
return.
Wholesale
power marketing activities may add volatility to earnings.
Utility
Holdings’ regulated electric utility engages in wholesale power marketing
activities that primarily involve the offering of utility-owned or contracted
generation into the MISO hourly and real time markets. As part of
these strategies, the Company may also execute energy contracts that are
integrated with portfolio requirements around power supply and
delivery. Presently, margin earned from these activities above or
below $10.5 million is shared evenly with customers. These earnings
from wholesale marketing activities may vary based on fluctuating prices for
electricity and the amount of electric generating capacity or purchased power
available beyond that needed to meet firm service requirements.
Catastrophic
events could adversely affect Utility Holdings’ facilities and
operations.
Catastrophic
events such as fires, earthquakes, explosions, floods, ice storms, tornados,
terrorist acts or other similar occurrences could adversely affect Utility
Holdings’ facilities, operations, financial condition and results of
operations.
Workforce
risks could affect Utility Holdings’ financial results.
The
Company is subject to various workforce risks, including but not limited to, the
risk that it will be unable to attract and retain qualified personnel; that it
will be unable to effectively transfer the knowledge and expertise of an aging
workforce to new personnel as those workers retire; that it will be unable to
react to a pandemic illness; and that it will be unable to reach collective
bargaining arrangements with the unions that represent certain of its workers,
which could result in work stoppages.
The
performance of Vectren’s nonutility businesses may impact Utility
Holdings.
Execution
of gas marketing strategies by ProLiance and Vectren’s nonutility gas retail
supply operations as well as the execution of Vectren’s coal mining and energy
infrastructure services strategies, and the success of efforts to invest in and
develop new opportunities in the nonutility business area is subject to a number
of risks. These risks include, but are not limited to, the effects of
weather; failure of installed performance contracting products to operate as
planned; failure to properly estimate the cost to construct projects; storage
field and mining property development; increased coal mining industry
regulation; potential legislation that may limit CO2 and other
greenhouse gas emissions; creditworthiness of customers and joint venture
partners; factors associated with physical energy trading activities, including
price, basis, credit, liquidity, volatility, capacity, and interest rate risks;
changes in federal, state or local legal requirements, such as changes in tax
laws or rates; and changing market conditions. Credit ratings of
individual entities within a consolidated organization can be influenced by
changes in business prospects and developments of other entities within that
organization. Thus, material adverse developments affecting those
other entities related to Vectren could result in a downgrade in Utility
Holdings’ credit ratings or outlook, limit its ability to access the debt
markets, bank financing and commercial paper markets and, thus, its
liquidity.
Vectren’s
nonutility businesses support Utility Holdings’ utilities pursuant to service
contracts by providing natural gas supply services, coal, and energy
infrastructure services. In most instances, Vectren’s ability to
maintain these service contracts depends upon regulatory approval and
negotiations with interveners, and there can be no assurance that it will be
able to obtain future service contracts, or that existing arrangements will not
be altered.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Gas Utility
Services
Indiana
Gas owns and operates four active gas storage fields located in Indiana covering
58,100 acres of land with an estimated ready delivery from storage capability of
6.0 BCF of gas with maximum peak day delivery capabilities of 151,000 MCF per
day. Indiana Gas also owns and operates three liquefied petroleum
(propane) air-gas manufacturing plants located in Indiana with the ability to
store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of
manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted with ProLiance for 16.7 BCF
of interstate pipeline storage service with a maximum peak day delivery
capability of 252,600 MMBTU per day. Indiana Gas’ gas delivery system
includes 13,000 miles of distribution and transmission mains, all of which are
in Indiana except for pipeline facilities extending from points in northern
Kentucky to points in southern Indiana so that gas may be transported to Indiana
and sold or transported by Indiana Gas to ultimate customers in
Indiana.
SIGECO
owns and operates three active underground gas storage fields located in Indiana
covering 6,100 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
108,500 MCF per day. In addition to its company owned storage
delivery capabilities, SIGECO has contracted with ProLiance for 0.5 BCF of
interstate pipeline storage service with a maximum peak day delivery capability
of 19,200 MMBTU per day. SIGECO's gas delivery system includes 3,200
miles of distribution and transmission mains, all of which are located in
Indiana.
The Ohio
operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants, all of which are located in Ohio. The plants
can store 0.5 million gallons of propane, and the plants can manufacture for
delivery 52,200 MCF of manufactured gas per day. In addition to its
propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF
of delivery service with a maximum peak day delivery capability of 246,100 MMBTU
per day. While the Company still has title to this delivery
capability, it has released it to those now supplying the Ohio operations with
natural gas, and those suppliers are responsible for the demand
charges. The Ohio operations’ gas delivery system includes 5,500
miles of distribution and transmission mains, all of which are located in
Ohio.
Electric Utility
Services
SIGECO's
installed generating capacity as of December 31, 2009, was rated at 1,298
MW. SIGECO's coal-fired generating facilities are the Brown Station
with two units of 490 MW of combined capacity, located in Posey County
approximately eight miles east of Mt. Vernon, Indiana; the Culley Station
with two units of
360 MW of combined capacity, and Warrick Unit 4 with 150 MW of
capacity. Both the Culley and Warrick Stations are located in Warrick
County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4)
located at the Brown Station; two Broadway Avenue Gas Turbines located in
Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1,
50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located
northeast of Evansville in Vanderburgh County, Indiana with a combined capacity
of 20 MW. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are
also equipped to burn oil. Total capacity of SIGECO's six gas
turbines is 295 MW, and they are generally used only for reserve, peaking, or
emergency purposes due to the higher per unit cost of generation. In
2009, SIGECO purchased a landfill gas electric generation project in Pike
County, Indiana with a total capability of 3 MW.
SIGECO's
transmission system consists of 932 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 34 substations with an
installed capacity of 4,500 megavolt amperes (Mva). The electric
distribution system includes 4,200 pole miles of lower voltage overhead lines
and 358 trench miles of conduit containing 2,000 miles of underground
distribution cable. The distribution system also includes 97
distribution substations with an installed capacity of 2,900 Mva and 54,000
distribution transformers with an installed capacity of 2,500 Mva.
SIGECO
owns utility property outside of Indiana approximating nine miles of 138,000
volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Property Serving as
Collateral
SIGECO's
properties are subject to the lien of the First Mortgage Indenture dated as of
April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and
Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM 3. LEGAL PROCEEDINGS
The
Company is party to various legal proceedings and audits and reviews by taxing
authorities and other government agencies arising in the normal course of
business. In the opinion of management, there are no legal
proceedings or other regulatory reviews or audits pending against the Company
that are likely to have a material adverse effect on its financial position,
results of operations, or cash flows. See the notes to the
consolidated financial statements regarding commitments and contingencies,
environmental matters, and rate and regulatory matters. The
consolidated condensed financial statements are included in “Item 8 Financial
Statements and Supplementary Data.”
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
2009, Utility Holdings paid dividends to its parent company totaling $20.6
million in each quarter.
During
2008, Utility Holdings paid dividends to its parent company totaling $20.8
million in each quarter.
In the
first quarter of 2010, the board of directors declared a $19.1 million dividend,
payable to Vectren.
Dividends
on shares of common stock are payable at the discretion of the board of
directors out of legally available funds. Future payments of
dividends, and the amounts of these dividends, will depend on the Company’s
financial condition, results of operations, capital requirements, and other
factors. Certain lending arrangements contain restrictive covenants,
including the maintenance of a total debt to total capitalization ratio, which
could limit the Company’s ability to pay dividends. These restrictive
covenants are not expected to affect the Company’s ability to pay dividends in
the near term.
ITEM 6. SELECTED FINANCIAL DATA
The
following selected financial data is derived from the Company’s audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K.
|
Year
Ended December 31,
|
||||||||||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
|
Operating
Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 1,596.2 | $ | 1,958.7 | $ | 1,759.0 | $ | 1,656.5 | $ | 1,781.8 | ||||||||||
|
Operating
income
|
238.0 | 254.6 | 244.4 | 209.0 | 216.6 | |||||||||||||||
|
Net
income
|
107.4 | 111.1 | 106.5 | 91.4 | 95.1 | |||||||||||||||
|
Balance
Sheet Data:
|
||||||||||||||||||||
|
Total
assets
|
$ | 3,823.1 | $ | 3,838.1 | $ | 3,643.7 | $ | 3,440.8 | $ | 3,391.2 | ||||||||||
|
Long-term
debt - net of current maturities
|
||||||||||||||||||||
|
&
debt subject to tender
|
1,254.8 | 1,065.1 | 1,062.6 | 1,025.3 | 997.8 | |||||||||||||||
|
Common
shareholder's equity
|
1,274.7 | 1,242.9 | 1,090.4 | 1,056.7 | 1,023.8 | |||||||||||||||
ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND
FINANCIAL CONDITION
Utility
Holdings generates revenue primarily from the delivery of natural gas and
electric service to its customers. Utility Holdings’ primary source of
cash flow results from the collection of customer bills and the payment for
goods and services procured for the delivery of gas and electric
services.
Vectren
has in place a disclosure committee that consists of senior management as well
as financial management. The committee is actively involved in the
preparation and review of Utility Holdings’ SEC filings.
|
The
following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes
thereto.
|
Executive Summary of
Consolidated Results of Operations
Results
In 2009,
Utility Holdings’ earnings were $107.4 million, compared to earnings of $111.1
million in 2008 and $106.5 million in 2007. The decrease in 2009
compared to 2008 reflects lower large customer usage and lower wholesale power
sales, both due to the recession, mild cooling weather, and an increase in
depreciation expense associated with rate base growth. Increased
revenues associated with regulatory initiatives, lower operating expenses, and
the return of market values associated with investments related benefit plans
partially offset these declines.
In 2008
compared to 2007, Utility Holdings’ earnings increased due primarily to a full
year of base rate increases in the Indiana service territories and increased
earnings from wholesale power operations. Increases were offset
somewhat by increased operating costs associated with maintenance and
reliability programs contemplated in the base rate cases and favorable weather
in 2007.
In the
Company’s electric and the Ohio natural gas service territory, which was not
fully protected by straight fixed variable rate design in 2009, management
estimates the margin impact of weather to be approximately $5.4 million
unfavorable or $0.04 per share compared to normal temperatures. In
2008, management estimates a $1.2 million favorable impact on margin compared to
normal or $0.01 per share, and in 2007 a $5.5 million favorable impact on margin
compared to normal or $0.04 per share.
Results of
Operations
Trends
in Operations
Margin
Throughout
this discussion, the terms Gas Utility margin and Electric Utility margin are
used. Gas Utility margin is calculated as Gas utility revenues less the
Cost of gas
sold. Electric Utility margin is calculated as Electric utility revenues
less Cost of fuel &
purchased power. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel and purchased power costs can be volatile and are
generally collected on a dollar-for-dollar basis from customers.
Rate
Design Strategies
Sales of
natural gas and electricity to residential and commercial customers are seasonal
and are impacted by weather. Trends in average use among natural gas
residential and commercial customers have tended to decline in recent years as
more efficient appliances and furnaces are installed and the price of natural
gas has been volatile. Normal temperature adjustment (NTA) and lost margin
recovery mechanisms largely mitigate the effect on Gas Utility margin that would
otherwise be caused by variations in volumes sold to these customers due to
weather and changing consumption patterns. Indiana Gas’ territory has both
an NTA since 2005 and lost margin recovery since 2006. SIGECO’s natural
gas territory has an NTA since 2005 and lost margin recovery since 2007.
The Ohio service territory had lost margin recovery since 2006. The
Ohio lost margin recovery mechanism ended when new base rates went into effect
in February 2009. This mechanism was replaced by a rate design,
commonly referred to as a straight fixed variable rate design, which is more
dependent on monthly service charge revenues and less dependent on volumetric
revenues than previous rate designs. This new rate design, which will be fully
implemented in February 2010, will mitigate most weather risk in
Ohio. SIGECO’s electric service territory has neither NTA nor lost
margin recovery mechanisms; however, rate designs proposed in a recently filed
rate case requests a lost margin recovery mechanism that works in tandem with
conservation initiatives, similar to rate designs undertaken in the Indiana gas
service territories.
Tracked
Operating Expenses
Margin is
also impacted by the collection of state mandated taxes, which fluctuate with
gas and fuel costs, as well as other tracked expenses. Expenses
subject to tracking mechanisms include Ohio uncollectible accounts expense and
percent of income payment plan expenses, costs associated with exiting the
merchant function and to perform service riser replacement in Ohio, Indiana gas
pipeline integrity management costs, costs to fund Indiana energy efficiency
programs, MISO transmission revenues and costs, as well as the gas cost
component of uncollectible accounts expense based on historical experience and
unaccounted for gas. Unaccounted for gas is also tracked in the Ohio
service territory. Certain operating costs, including depreciation,
associated with operating environmental compliance equipment at electric
generation facilities and regional electric transmission investments are also
tracked.
Recessionary
Impacts
Gas and
electric margin generated from sales to large customers (generally industrial
and other contract customers) is primarily impacted by overall economic
conditions and changes in demand for those customers’ products. The
recent recession has had and may continue to have some negative impact on sales
to and usage by both gas and electric large customers. This impact
has included, and may continue to include, tempered growth, significant
conservation measures, and increased plant closures and
bankruptcies. While no one industrial customer comprises 10 percent
of consolidated revenues, the top five industrial electric customers comprise
approximately 12 percent of electric utility margin for the year ended December
31, 2009, and therefore any significant decline in their collective margin could
adversely impact operating results. Deteriorating economic conditions
may also lead to continued lower residential and commercial customer
counts. Further, resulting from the lower power prices, decreased
demand for electricity and higher coal prices associated with contracts
negotiated last year, the Company’s coal fired generation has been dispatched
less often by the MISO. This has resulted in lower wholesale sales,
more power being purchased from the MISO for native load requirements, and
larger coal inventories.
Following
is a discussion and analysis of margin generated from regulated utility
operations.
Gas
Utility Margin (Gas utility revenues less Cost of gas sold)
Gas
utility margin and throughput by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Gas
utility revenues
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Cost
of gas sold
|
618.1 | 983.1 | 847.2 | |||||||||
|
Total
gas utility margin
|
$ | 447.9 | $ | 449.6 | $ | 422.2 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 388.8 | $ | 385.5 | $ | 360.9 | ||||||
|
Industrial
customers
|
46.8 | 51.2 | 48.7 | |||||||||
|
Other
|
12.3 | 12.9 | 12.6 | |||||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
106.5 | 114.8 | 108.4 | |||||||||
|
Industrial
customers
|
78.0 | 91.5 | 86.2 | |||||||||
|
Total
sold & transported volumes
|
184.5 | 206.3 | 194.6 | |||||||||
For the
year ended December 31, 2009, gas utility margins were $447.9 million, a slight
decrease of $1.7 million, compared to 2008. Management estimates a
$4.4 million year over year decrease in industrial customer margin associated
with lower volumes sold, and slightly lower residential and commercial customer
counts decreased margin approximately $1.7 million. These
recessionary impacts were offset by margin associated with regulatory
initiatives. Among all customer classes, margin increases associated
with regulatory initiatives, including the full impact of the Vectren North base
rate increase effective in February 2008 and the Vectren Ohio base rate increase
effective February 2009, were $8.4 million year over year. The impact
of operating costs, including revenue and usage taxes, recovered in margin was
unfavorable $2.9 million year over year, reflecting lower revenue taxes offset
by higher pass through operating expenses. The remaining decrease
primarily relates to Ohio weather and lower miscellaneous revenues associated
with reconnection fees. The lower fees as well as the lower revenue
and usage taxes correlate with lower year over year gas costs. The
average cost per dekatherm of gas purchased during 2009 was $5.97 compared to
$9.61 in 2008 and $8.14 in 2007.
For the
year ended December 31, 2008, gas utility margins increased $27.4 million
compared to 2007. Regulatory initiatives, including the Vectren North
base rate increase, effective February 2008 and the Vectren South base rate case
effective August 2007, added $15.4 million in margin. In 2008, Ohio
weather was 8 percent colder than the prior year and resulted in an estimated
increase in margin of approximately $3.2 million compared to
2007. Operating costs, including revenue and usage taxes, recovered
in margin, increased gas margin $7.8 million.
Electric
Utility Margin (Electric utility revenues less Cost of fuel & purchased
power)
Electric
utility margin and volumes sold by customer type follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Electric
utility revenues
|
$ | 528.6 | $ | 524.2 | $ | 487.9 | ||||||
|
Cost
of fuel & purchased power
|
194.3 | 182.9 | 174.8 | |||||||||
|
Total
electric utility margin
|
$ | 334.3 | $ | 341.3 | $ | 313.1 | ||||||
|
Margin
attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
$ | 221.9 | $ | 218.6 | $ | 198.6 | ||||||
|
Industrial
customers
|
84.5 | 82.9 | 78.3 | |||||||||
|
Municipals
& other customers
|
7.2 | 7.3 | 15.3 | |||||||||
|
Subtotal:
Retail
|
$ | 313.6 | $ | 308.8 | $ | 292.2 | ||||||
|
Wholesale
margin
|
20.7 | 32.5 | 20.9 | |||||||||
|
Total
electric utility margin
|
$ | 334.3 | $ | 341.3 | $ | 313.1 | ||||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||||
|
Residential
& commercial customers
|
2,760.8 | 2,850.5 | 3,042.9 | |||||||||
|
Industrial
customers
|
2,258.9 | 2,409.1 | 2,538.5 | |||||||||
|
Municipals
& other
|
20.0 | 63.8 | 635.1 | |||||||||
|
Total
retail & firm wholesale volumes sold
|
5,039.7 | 5,323.4 | 6,216.5 | |||||||||
Retail
Electric
retail utility margin was $313.6 million for the year ended December 31, 2009,
and compared to 2008 increased $4.8 million. Increased margin among
the customer classes associated with returns on pollution control equipment and
other investments totaled $4.5 million year over year, and margin associated
with tracked costs such as recovery of MISO and pollution control operating
expenses increased $10.3 million . Management estimates weather,
driven primarily by cooling weather 10 percent milder than the prior year,
decreased residential and commercial margin $5.2 million compared to
2008. Industrial margins, net of the impacts of regulatory
initiatives and recovery of tracked costs, decreased approximately $4.9 million
due primarily to the weak economy. The industrial decreases are due
primarily to lower usage; however, usage began to stabilize during the third and
fourth quarters.
Electric
retail utility margin was $308.8 million for the year ended December 31, 2008,
an increase of approximately $16.6 million compared to 2007. The base
rate increase that went into effect on August 15, 2007, produced incremental
margin of $27.0 million year over year when netted with municipal contracts that
were allowed to expire. Management estimates the year over year
decreases in usage by residential and commercial customers due to weather, which
was very warm the prior summer, to be $7.5 million. Other usage
declines due in part to a weakening economy and conservation measures were the
primary reason for the remaining decrease.
Margin from Wholesale
Electric Activities
Periodically,
generation capacity is in excess of native load. The Company markets
and sells this unutilized generating and transmission capacity to optimize the
return on its owned assets. A majority of the margin generated from
these activities is associated with wholesale off-system sales, and
substantially all off-system sales occur into the MISO Day Ahead and Real Time
markets.
Further
detail of Wholesale
activity follows:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Off-system
sales
|
$ | 6.1 | $ | 23.2 | $ | 16.9 | ||||||
|
Transmission
system sales
|
14.6 | 9.3 | 4.0 | |||||||||
|
Total
wholesale margin
|
$ | 20.7 | $ | 32.5 | $ | 20.9 | ||||||
For the year ended December 31, 2009, wholesale margin was $20.7 million, representing a decrease of $11.8 million, compared to 2008. Of the decrease, $17.1 million relates to lower margin retained by the Company from off-system sales. The Company experienced lower wholesale power marketing margins due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs. During 2008, margin from off-system sales retained by the Company increased $6.3 million, compared to 2007, due to an increase in off peak volumes available for sale off system. This increase in volumes was driven primarily by expiring municipal contracts and increases in wholesale prices. Off-system sales totaled 603.6 GWh in 2009, compared to 1,512.9 GWh in 2008 and 921.3 GWh in 2007. The base rate increase effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August. Results in 2008 and 2009 reflect the impact of that sharing.
Beginning
in June 2008, the Company began earning a return on electric transmission
projects constructed by the Company in its service territory that meet the
criteria of MISO’s regional transmission expansion plans. Margin
associated with these projects and other transmission system operations
increased $5.3 million in 2009 compared to 2008. These returns also
primarily account for the $5.3 million increase in transmission system sales in
2008 compared to 2007.
Purchased
Power
The
Company’s mix of generated and purchased electricity changed during 2009
compared to prior years. For the years ended December 31, 2009, 2008,
and 2007, respectively, the Company purchased approximately 1,159 GWh, 372 GWh,
and 416 GWh of power from the MISO and other sources. The total cost
associated with these volumes of purchased power is approximately $43 million,
$26 million, and $26 million in 2009, 2008, and 2007 respectively, and is
included in the Cost of fuel
& purchased power.
Operating
Expenses
Other
Operating
For year
ended December 31, 2009, other
operating expenses were $304.6 million, increasing $4.3 million compared
to 2008. Approximately $10.9 million of the change results from
increased costs directly recovered through utility margin. Examples
of such tracked costs include Ohio uncollectible accounts expense, Indiana gas
pipeline integrity management costs, costs to fund Indiana energy efficiency
programs, and MISO transmission revenues and costs, among
others. Increases in other operating expenses in 2009, not directly
recovered in margin, include an approximate $6.3 million increase for certain
compensation costs and a $4.1 million increase associated with environmental
matters. All other operating expenses were approximately
$17.0 million lower than the prior year driven primarily by
reductions in electric maintenance costs and lower chemical
costs. Despite significantly lower gas costs due to the recession,
Indiana uncollectible accounts expense was only slightly favorable compared to
2008.
For the year ended December 31, 2008, other operating expenses were $300.3 million, which represents an increase of $34.2 million, compared to 2007. Costs in 2008 resulting from increased maintenance and other reliability activities, including amortization of prior deferred costs contemplated in base rate increases, increased approximately $35.3 million year over year. Operating costs that are directly recovered in utility margin increased $4.2 million year over year. Costs associated with lower performance compensation and share based compensation and other cost reductions partially offset these increases.
Depreciation
& Amortization
In 2009,
depreciation &
amortization expense increased $15.4 million compared to
2008. The increase in depreciation is due largely to plant
additions. Plant additions include the approximate $100 million
SO2
scrubber placed into service January 1, 2009, for which depreciation totaling
$5.6 million is directly recovered in electric utility
margin. Depreciation expense increased $7.1 million in 2008 compared
to 2007. Expense in 2008 includes $3.8 million of increased
amortization associated with prior electric demand side management costs to be
recovered pursuant to the August 15,
2007 electric base rate order. The remaining increases are also
attributable to increased utility plant in service.
Taxes
Other Than Income Taxes
Taxes other than income taxes
decreased $12.0 million in 2009 compared to 2008 and increased $4.2 million in
2008 compared to 2007. These taxes are primarily revenue-related
taxes. The variations are primarily attributable to volatility in
revenues, inclusive of changes in natural gas prices and gas volumes
sold. These tax expenses are recovered through revenue.
Other
Income-Net
Other income-net reflects
income of $7.8 in 2009, compared to $4.0 million in 2008 and $9.4 million in
2007. The variations are primarily due to volatile market values
associated with investments related to benefit plans.
Interest
Expense
For the
year ended December 31, 2009, interest expense was $79.2
million, which represents a slight decrease of $0.7 million compared to
2008. Lower short-term interest rates and lower average short-term
debt balances have favorably affected interest expense year over year and are
reflective of lower gas prices and the issuance of new long-term
debt. Offsetting the favorable impacts of lower rates and short-term
balances is the impact of two long-term financing transactions completed in
2009. The long-term financing transactions include a second quarter
issuance by Utility Holdings of $100 million in unsecured eleven year notes with
an interest rate of 6.28 percent and a third quarter completion by SIGECO of a
$22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an
interest rate of 5.4 percent.
For the
year ended December 31, 2008, interest expense was $79.9
million, a decrease of $0.7 million compared to 2007, as lower average
short-term debt levels and lower average short-term interest rates were
partially offset by higher long-term balances and interest rates.
Income
Taxes
Federal
and state income taxes
decreased $8.4 million in 2009 compared to 2008 and increased $0.9 million in
2008 compared to 2007. The changes are impacted primarily by
fluctuations in pre-tax income and lower effective tax rates.
Environmental
Matters
Clean Air
Act
The Clean
Air Interstate Rule (CAIR) is an allowance cap and trade program requiring
further reductions from coal-burning power plants in NOx emissions beginning
January 1, 2009 and SO2 emissions
beginning January 1, 2010, with a second phase of reductions in 2015. On
July 11, 2008, the US Court of Appeals for the District of Columbia vacated the
federal CAIR regulations. Various parties filed motions for
reconsideration, and on December 23, 2008, the Court reinstated the CAIR
regulations and remanded the regulations back to the USEPA for promulgation of
revisions in accordance with the Court’s July 11, 2008 Order. Thus,
the original version of CAIR promulgated in March of 2005 remains effective
while USEPA revises it per the Court’s guidance. SIGECO is in
compliance with the current CAIR Phase I annual NOx reduction requirements in
effect on January 1, 2009 and is also in compliance with SO2 reductions
effective January 1, 2010. It is possible that a revised CAIR will
require further reductions in NOx and SO2 from
SIGECO’s generating units. Utilization of the Company’s inventory of
NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of these
allowances were granted to the Company at zero cost, so these changes will not
impact the carrying value.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. In response to the court decision, USEPA has announced
that it intends to publish proposed Maximum Achievable Control Technology
standards for mercury in 2010. It is uncertain what emission limit
the USEPA is considering, and whether they will address hazardous pollutants in
addition to mercury. It is also possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. Prior to being included in base rates, return
on investments made and recovery of related operating expenses were recovered
through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism, which is periodically updated for actual
costs incurred less post in-service depreciation expense. The Company
has invested approximately $100 million in this project. The scrubber
was placed into service on January 1, 2009. Recovery through a rider
mechanism of associated operating expenses including depreciation expense
associated with the scrubber also began on January 1, 2009. The
SO2
scrubber is in compliance with the additional SO2 reductions
required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s
coal fired generating fleet is 100 percent scrubbed for SO2 and 90
percent controlled for NOx. SIGECO's investments in scrubber, SCR and
fabric filter technology allows for compliance with existing regulations and
should position it to comply with future reasonable pollution control
legislation, if and when, reductions in mercury and further reductions in NOx
and SO2 are
promulgated by USEPA.
Climate
Change
Vectren
is committed to responsible environmental stewardship and conservation
efforts. While scientific uncertainties exist and the debate
surrounding global climate change is ongoing, current information suggests a
potential for adverse economic and social consequences should world-wide carbon
dioxide (CO2) and other
greenhouse gas emissions continue at present levels.
The
Company emits greenhouse gases (GHG) primarily from its fossil fuel electric
generation plants. The Company uses methodology described in the Acid
Rain Program (under Title IV of the Clean Air Act) to calculate its level of
direct CO2 emissions
from its fossil fuel electric generating plants. The Company’s direct
CO2
emissions from its plants over the past 5 years are represented
below:
|
(in
thousands)
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||
|
Direct
CO2
Emissions (tons)
|
5,500
|
1/
|
8,029
|
7,995
|
7,827
|
8,242
|
||||
|
1/
|
The
decline in emissions from 2008 to 2009 is primarily due to recessionary
impacts that resulted in a 30 percent decrease in
generation. It is not clear to what extent this recent
reduction may continue.
|
Based on
2005 data made available through the Emissions and Generation Resource
Integrated Database (eGRID) maintained by the USEPA, the Company’s direct
CO2
emissions from its fossil fuel electric generation that report under the Acid
Rain Program were less than one half of one percent of all emissions in the
United States from similar sources.
Emissions
from other Company operations, including those from its natural gas distribution
operations, are monitored internally using the Department of Energy 1605(b)
Standard, and the Company is currently assessing how to effectively report these
emissions in relation to the new mandatory reporting regulations set forth by
the USEPA.
The need
to reduce CO2 and other
greenhouse gas emissions, yet provide affordable energy, requires thoughtful
balance. For these reasons, Vectren supports a national climate change policy
with the following elements:
|
·
|
An
inclusive scope that involves all sectors of the economy and sources of
greenhouse gases, and recognizes early actions and investments made to
mitigate greenhouse gas emissions;
|
|
·
|
Provisions
for enhanced use of renewable energy sources as a supplement to base load
coal generation including effective energy conservation, demand side
management and generation efficiency
measures;
|
|
·
|
A
flexible market-based cap and trade approach with zero cost allowance
allocations to coal-fired electric generators. The approach
should have a properly designed economic safety valve in order to reduce
or eliminate extreme price spikes and potential price volatility. A long
lead time must be included to align nearer-term technology capabilities
and expanded generation efficiency and other enhanced renewable
strategies, ensuring that generation sources will rely less on natural gas
to meet short term carbon reduction requirements. This new
regime should allow for adequate resource and generation planning and
remove existing impediments to efficiency enhancements posed by the
current New Source Review provisions of the Clean Air
Act;
|
|
·
|
Inclusion
of incentives for investment in advanced clean coal technology and support
for research and development;
|
|
·
|
A
strategy supporting alternative energy technologies and biofuels and
increasing the domestic supply of natural gas to reduce dependence on
foreign oil and imported natural gas;
and
|
|
·
|
The
allocation of zero cost allowances to natural gas distribution companies
if those companies are required to hold allowances for the benefit of the
end use customer.
|
Current
Initiatives to Increase Conservation & Reduce Emissions
The
Company is committed to a policy that reduces greenhouse gas emissions and
conserves energy usage. Evidence of this commitment
includes:
|
·
|
Focusing
the Company’s mission statement and purpose on corporate sustainability
and the need to help customers conserve and manage energy
costs;
|
|
·
|
Building
a renewable energy portfolio to complement base load coal-fired generation
in advance of mandated renewable energy portfolio
standards;
|
|
·
|
Implementing
conservation initiatives in the Company’s Indiana and Ohio gas utility
service territories;
|
|
·
|
Participation
in an electric conservation and demand side management collaborative with
the OUCC and other customer advocate
groups;
|
|
·
|
Evaluating
potential carbon requirements with regard to new generation, other fuel
supply sources, and future environmental compliance
plans;
|
|
·
|
Reducing
the Company’s carbon footprint by measures such as purchasing hybrid
vehicles and optimizing generation efficiencies;
and
|
Legislative
Actions & Other Climate Change Initiatives
The U.S.
House of Representatives has passed a comprehensive energy bill that includes a
carbon cap and trade program in which there is a progressive cap on greenhouse
gas emissions and an auctioning and subsequent trading of allowances among those
that emit greenhouse gases, a federal renewable portfolio standard, and utility
energy efficiency targets. Current proposed legislation also requires
local natural gas distribution companies to hold allowances for the benefit of
their customers. As of the date of this filing, the Senate has not
passed a bill, and the House bill is not law.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in Indiana,
the state is an observer to the Midwestern Regional Greenhouse Gas Reduction
Accord.
In
advance of a federal or state renewable portfolio standard, SIGECO received IURC
approval to purchase a 3 MW landfill gas generation facility from a related
entity. The facility was purchased in 2009 and is directly
interconnected to the Company’s distribution system. In 2009, the
Company also executed a long term purchase power commitment for 50 MW of wind
energy. These transactions supplement a 30 MW wind energy purchase
power agreement executed in 2008. At December 31, 2009, the Company’s
renewable portfolio is approximately 5 percent of total generation
sources.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. In April of 2009, the USEPA published its proposed
endangerment finding for public comment. The proposed endangerment
finding concludes that carbon emissions from mobile sources pose an endangerment
to public health and the environment. The endangerment finding was
finalized in December of 2009, and is the first step toward USEPA regulating
carbon emissions through the existing Clean Air Act in the absence of specific
carbon legislation from Congress. Therefore, any new regulations
would likely also impact major stationary sources of greenhouse
gases. The USEPA has recently finalized a mandatory greenhouse gas
emissions registry which will require reporting of emissions beginning in 2011
(for the emission year 2010). The USEPA has also recently proposed a
revision to the PSD (Prevention of Significant Deterioration) and Title V
permitting rules which would require facilities that emit 25,000 tons or more of
greenhouse gases a year to obtain a PSD permit for new construction or a
significant modification of an existing facility. If these proposed
rules were adopted, they would apply to SIGECO’s generating
facilities.
Impact
of Legislative Actions & Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants and
natural gas distribution businesses. Further, any legislation would likely
impact the Company’s generation resource planning decisions. At this time
and in the absence of final legislation, compliance costs and other effects
associated with reductions in greenhouse gas emissions or obtaining renewable
energy sources remain uncertain. The Company has gathered preliminary
estimates of the costs to comply with a cap and trade approach to controlling
greenhouse gas emissions. A preliminary investigation demonstrated
costs to comply would be significant, first with regard operating expenses for
the purchase of allowances, and later for capital expenditures as technology
becomes available to control greenhouse gas emissions. However, these
compliance cost estimates are based on highly uncertain assumptions, including
allowance prices and energy efficiency targets. Costs to purchase
allowances that cap greenhouse gas emissions should be considered a cost of
providing electricity and gas, and as such, the Company believes recovery should
be timely reflected in rates charged to customers. Approximately 20
percent of electric volumes sold in 2008 were delivered to municipal and other
wholesale customers. As such, reductions in these volumes in 2009
coupled with the flexibility to further modify the level of these transactions
in future periods may help with compliance since emission targets are expected
to be based on pre-2008 levels.
Ash Ponds & Coal Ash
Disposal Regulations
The USEPA
is considering additional regulatory measures affecting the management and
disposal of coal combustion products, such as ash generated by the
Company’s coal-fired power plants. Additional laws and regulations under
consideration more stringently regulate these byproducts, including the
potential for coal ash to be considered a hazardous waste in certain
circumstances. The USEPA has indicated that it intends to propose a rule
during 2010. At this time, the Company is unable to predict the outcome
any such revised regulations might have on operating results, financial
position, or liquidity.
Jacobsville Superfund
Site
On July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The
USEPA has identified four sources of historic lead
contamination. These four sources shut down manufacturing operations
years ago. When drawing up the boundaries for the listing, the USEPA
included a 250 acre block of properties surrounding the Jacobsville
neighborhood, including Vectren's Wagner Operations Center. Vectren's
property has not been named as a source of the lead
contamination. Vectren's own soil testing, completed during the
construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils above industrial cleanup
levels. At this time, it is anticipated that the USEPA may request
only additional soil testing at some future date.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that owned or
operated these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded cumulative costs
that it reasonably expects to incur totaling approximately $23.2
million. The estimated accrued costs are limited to Indiana Gas’
share of the remediation efforts. Indiana Gas has arrangements in
place for 19 of the 26 sites with other potentially responsible parties (PRP),
which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50
percent.
With
respect to insurance coverage, Indiana Gas has settled with all known insurance
carriers under insurance policies in effect when these plants were in operation
in an aggregate amount approximating $20.8 million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another waste
disposal site subject to potential environmental remediation
efforts. With respect to that lawsuit, in an October 2009 court
decision, SIGECO was found to be a PRP at the site. However, the
Court must still determine whether such costs should be allocated among a number
of PRPs, including the former owners of the site. SIGECO has filed a
declaratory judgment action against its insurance carriers seeking a judgment
finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit.
SIGECO
has recorded cumulative costs that it reasonably expects to incur related to
these environmental matters totaling approximately $11.1
million. However, given the uncertainty surrounding the allocation of
PRP responsibility associated with the May 2007 lawsuit and other matters, the
total costs that may be incurred in connection with addressing all of these
sites cannot be determined at this time. With respect to insurance
coverage, SIGECO has settled with certain of its known insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.1 million; negotiations are ongoing with others.
Total
costs expected to be incurred are estimated by management using assumptions
based on actual costs incurred, the timing of expected future payments, and
inflation factors, among others. While the Company’s utilities have
recorded all costs which they presently expect to incur in connection with
activities at these sites, it is possible that future events may require some
level of additional remedial activities which are not presently foreseen and
those costs may not be subject to PRP or insurance recovery. As of
December 31, 2009 and December 31, 2008, approximately $6.5 million of accrued,
but not yet spent, remediation costs are included in Other Liabilities related to
both the Indiana Gas and SIGECO sites.
Rate
& Regulatory Matters
Gas and
electric operations with regard to retail rates and charges, terms of service,
accounting matters, issuance of securities, and certain other operational
matters specific to its Indiana customers are regulated by the
IURC. The retail gas operations of the Ohio operations are subject to
regulation by the PUCO.
Gas rates
in Indiana contain a gas cost adjustment (GCA) clause. The GCA clause allows the
Company to charge for changes in the cost of purchased gas. Electric
rates contain a fuel adjustment clause (FAC) that allows for adjustment in
charges for electric energy to reflect changes in the cost of
fuel. The net energy cost of purchased power, subject to a variable
benchmark based on NYMEX natural gas prices, is also recovered through
regulatory proceedings. The IURC approved agreement authorizing this
recovery expires in April 2010, and is subject to automatic annual
renewals.
GCA and
FAC procedures involve periodic filings and IURC hearings to establish the
amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. The Company records any
under-or-over-recovery resulting from gas and fuel adjustment clauses each month
in margin. A corresponding asset or liability is recorded until the
under-or-over-recovery is billed or refunded to utility customers.
The IURC
has also applied the statute authorizing GCA and FAC procedures to reduce rates
when necessary to limit net operating income to a level authorized in its last
general rate order through the application of an earnings test. These
earnings tests have not had any material impact to the Company’s recent
operating results.
Prior to
October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery
(GCR) clause. The GCR clause operated similar to the GCA clause in
Indiana. The PUCO periodically audited the GCR rates. The PUCO has
completed all audits of periods prior to October 2008, and no issues or findings
are outstanding. After October 1, 2008, the Company is no longer the
supplier, and the GCR is no longer necessary.
Vectren South Electric Base
Rate Filing
On
December 11, 2009, the Company filed a request with the IURC to adjust its
electric base rates in its South service territory. The requested
increase in base rates addresses capital investments, a modified electric rate
design that facilitates a partnership between the Company and customers to
pursue energy efficiency and conservation, and new energy efficiency programs to
complement those currently offered for natural gas customers. In
total the request approximated $54 million. The request addresses the
roughly $325 million spent in infrastructure construction since its last base
rate increase in August 2007 that was needed to continue to provide reliable
service. Most of the remainder of the request is to account for the
now lower overall sales levels resulting from the recession. A
portion of the request reflects a slight increase in annual operating and
maintenance costs since the last rate case, nearly four years
ago. The rate design proposed in the filing would break the link
between customers’ consumption and the utility’s rate of return, thereby
aligning the utility’s and customers’ interests in using less
energy. The request assumes an overall rate of return of 7.62 percent
on rate base of approximately $1,294 million and an allowed return on equity
(ROE) of 10.7 percent. Based upon timelines prescribed by the IURC at
the start of these proceedings, a decision is expected to be issued at the end
of 2010.
VEDO Gas Base Rate Order
Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also adjusted the rate design used to collect the agreed-upon revenue from
VEDO's customers. The order allows for the phased movement toward a
straight fixed variable rate design which places substantially all of the fixed
cost recovery in the customer service charge. A straight fixed
variable design mitigates most weather risk as well as the effects of declining
usage, similar to the Company’s lost margin recovery mechanism, which expired
when this new rate design went into effect on February 22, 2009. In
2008, annual results include approximately $4.3 million of revenue from a lost
margin recovery mechanism that did not continue once this base rate increase
went into effect. After year one, nearly 90 percent of the combined
residential and commercial base rate margins were recovered through the customer
service charge. The OCC has filed a request for rehearing on the rate
design finding by the PUCO. The rehearing request mirrors similar
requests filed by the OCC in each case where the PUCO has approved similar rate
designs. The Ohio Supreme Court has yet to act on the OCC’s request
in this instance, but in two similar cases, the Court denied such
requests.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of uncollectible accounts
and percent of income payment plan (PIPP) expenses; base rate recovery of
pipeline integrity management expense; timely recovery of costs associated with
the accelerated replacement of bare steel and cast iron pipes, as well as
certain service risers; and expanded conservation programs now totaling up to $5
million in annual expenditures. The straight fixed variable rate
design will be fully phased in by February 2010.
VEDO Continues the Process
to Exit the Merchant Function
On August
20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers
to provide the gas commodity to the Company for resale to its customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. This auction, which is effective from October 1, 2008 through
March 31, 2010, is the initial step in exiting the merchant function in the
Company’s Ohio service territory. The approach eliminated the need
for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits.
In October 2008, VEDO’s entire natural gas inventory was transferred, receiving
proceeds of approximately $107 million.
The
second phase of the exit process begins on April 1, 2010, during which the
Company will no longer sell natural gas directly to these
customers. Rather, state-certified Competitive Retail Natural Gas
Suppliers, that are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers for 12 months at
auction-determined standard pricing. That auction was conducted on
January 12, 2010, and the auction results were approved by the PUCO on January
13. The plan approved by the PUCO requires that the Company conduct at
least two auctions during this phase. As such, the Company will conduct
another auction in advance of the second 12-month term, which will commence on
April 1, 2011. Consistent with current practice, customers will
continue to receive one bill for the delivery of natural gas
service.
The PUCO
has also provided for an Exit Transition Cost rider, which allows the Company to
recover costs associated with the transition. As the cost of gas is
currently passed through to customers through a PUCO approved recovery
mechanism, the impact of exiting the merchant function should not have a
material impact on Company earnings or financial condition.
Vectren North Gas Base Rate
Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
the settlement agreement reached in its Vectren North gas rate case. The
order provided for a base rate increase of $16.3 million and a return on equity
(ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate
base of approximately $793 million. The order also provides for the
recovery of $10.6 million of costs through separate cost recovery mechanisms
rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for AFUDC and the deferral
of depreciation expense after the projects go in service but before they are
included in base rates. To qualify for this treatment, the annual
expenditures are limited to $20 million and the treatment cannot extend beyond
four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a uncollectible accounts expense level based on
historical experience and unaccounted for gas through the existing GCA
mechanism, and tracking of pipeline integrity management
expense.
Vectren South Gas Base Rate
Order Received
On August
1, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s gas rate case. The order provided
for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an
overall rate of return of 7.2 percent on rate base of approximately $122
million. The order also provided for the recovery of $2.6 million of
costs through separate cost recovery mechanisms rather than base
rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for AFUDC and the deferral
of depreciation expense after the projects go in service but before they are
included in base rates. To qualify for this treatment, the annual
expenditures are limited to $3 million and the treatment cannot extend beyond
three years on each project.
With this
order, the Company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a uncollectible accounts expense level based on
historical experience and unaccounted for gas through the existing gas cost
adjustment mechanism, and tracking of pipeline integrity management
expense.
Vectren South Electric Base
Rate Order Received
In August
2007, the Company received an order from the IURC which approved the settlement
reached in Vectren South’s electric rate case. The order provided for an
approximate $60.8 million electric rate increase to cover the Company’s cost of
system growth, maintenance, safety and reliability. The order provided
for, among other things: recovery of ongoing costs and deferred costs associated
with the MISO; operations and maintenance (O&M) expense increases related to
managing the aging workforce, including the development of expanded
apprenticeship programs and the creation of defined training programs to ensure
proper knowledge transfer, safety and system stability; increased O&M
expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by Vectren sharing equally with
customers any profit earned above or below $10.5 million of wholesale power
margin; recovery of and return on the investment in past demand side management
programs to help encourage conservation during peak load periods; timely
recovery of the Company’s investment in certain new electric transmission
projects that benefit the MISO infrastructure; an overall rate of return of 7.32
percent on rate base of approximately $1,044 million and an allowed ROE of 10.4
percent.
MISO
Since
2002 and with the IURC’s approval, the Company has been a member of the MISO, a
FERC approved regional transmission organization. The MISO serves the
electrical transmission needs of much of the Midwest and maintains operational
control over the Company’s electric transmission facilities as well as that of
other Midwest utilities. Since April 1, 2005, the Company has been an
active participant in the MISO energy markets, bidding its owned generation into
the Day Ahead and Real Time markets and procuring power for its retail customers
at Locational Marginal Pricing (LMP) as determined by the MISO
market.
Historically,
the Company has typically been in a net sales position with MISO as generation
capacity is in excess of that needed to serve native load and is from time to
time in a net purchase position. When the Company is a net seller such net
revenues are included in Electric utility revenues and
when the Company is a net purchaser such net purchases are included in Cost of fuel & purchased
power. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO Day Ahead and Real-Time markets. The Company also has municipal
customers served through the MISO and for which the Company transmits power to
the MISO for delivery to those customers. Net revenues from wholesale
activities, inclusive of revenues associated with these municipal contracts,
totaled $20.8 million in 2009, $57.6 million in 2008, and $35.0 million in
2007. The base rate case effective August 17, 2007, requires that
wholesale margin (net revenues less the cost of fuel & purchased power)
inclusive of this MISO wholesale activity earned above or below $10.5 million be
shared equally with retail customers as measured on a fiscal year ending in
August.
Recently,
MISO market prices have fallen and the Company has more frequently been a net
purchaser. In addition, the Company also receives power through the
MISO associated with its wind and other power purchase
agreements. Including these power purchase agreements, the Company
purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in
2008, and $18.2 million in 2007. To the extent these power purchases
are used for retail load, they are subject to FAC filings.
The
Company also receives transmission revenue that results from other MISO members’
use of the Company’s transmission system. These revenues are also
included in Electric utility
revenues. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered from / refunded to retail
customers through tracking mechanisms.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to recover costs associated with ASM. To
date impacts from the ASM have been minor.
The need
to expend capital for improvements to the regional transmission system, both to
SIGECO’s facilities as well as to those facilities of adjacent utilities, over
the next several years is expected to be significant. Beginning in
June 2008, the Company began timely recovering its investment in certain new
electric transmission projects that benefit the MISO regional infrastructure at
a FERC approved rate of return. Such revenues recorded in Electric utility revenues
associated with projects meeting the criteria of MISO’s transmission
expansion plans totaled $9.1 million in 2009 and $4.8 million in
2008.
One such
project currently under construction is an interstate 345 kilovolt
transmission line that will connect Vectren’s A.B. Brown Generating Station to a
station in Indiana owned by Duke Energy to the north and to a station in
Kentucky owned by Big Rivers Electric Corporation to the south. Throughout
the project, SIGECO is to recover an approximate 10 percent return,
inclusive of the FERC approved equity rate of return of
12.38 percent, on capital investments through a rider mechanism
which is updated annually for estimated costs to be incurred. Of the total
investment, which is expected to approximate $75 million, as of December 31,
2009, the Company has invested approximately $21.3 million. The
Company expects this project to be fully operational in 2011. At that
time, any operating expenses including depreciation expense are also expected to
be recovered through a FERC approved rider mechanism. Further, the
approval allows for recovery of expenditures made even in the event currently
unforeseen difficulties delay or permanently halt the project.
Impact of Recently Issued
Accounting Guidance
Business
Combinations
On
January 1, 2009, the Company adopted new FASB guidance related to business
combinations. This guidance establishes principles and requirements
for how the acquirer of an entity (1) recognizes and measures the identifiable
assets acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. The guidance applies to all transactions or
other events in which one entity acquires control of one or more businesses and
applies to all business entities. To date, the adoption of this
standard has not had a material impact.
Subsequent
Events
The
Company adopted new FASB guidance related to management’s review of subsequent
events on June 30, 2009. In the instance of a public registrant such
as the Company, this guidance establishes the accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are “issued”, as that term is defined in the guidance. Such
disclosure is included in Note 2 to these consolidated financial
statements.
Accounting
Standards Codification
The
Company adopted FASB guidance related to the FASB Accounting Standards
Codification (ASC) and the Hierarchy of GAAP. This statement
identifies the sources of accounting principles and the framework for selecting
the principles used in the preparation of financial statements of
nongovernmental entities that are presented in conformity with GAAP in the
United States. This statement replaces prior guidance related to the
hierarchy of GAAP and establishes the FASB ASC as the source of authoritative
accounting principles recognized by the FASB. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources
of authoritative GAAP for all SEC registrants. The adoption of this
guidance did not have any impact on amounts recorded on the financial
statements.
Accounting
for Liabilities Measured at Fair Value with a Third-Party Credit
Enhancement
On
January 1, 2009, the Company adopted FASB guidance related to issuer’s
accounting for liabilities measured at fair value with a third-party credit
enhancement. This guidance states that companies should not include
the effect of third-party credit enhancements in the fair value measurement of
the related liabilities. The guidance also requires companies with
outstanding liabilities measured or disclosed at fair value to disclose the
existence of credit enhancements, to disclose valuation techniques used to
measure liabilities and to include a discussion of changes, if any, from the
valuation techniques used to measure liabilities in prior periods.
As of
December 31, 2009, the Company has approximately $250.0 million of debt
instruments that are supported by a third party credit enhancement feature such
as insurance from a monoline insurer or a letter of credit posted by third party
that supports the Company’s credit facilities. The Company’s
valuation techniques did not materially change as a result of the adoption of
this guidance.
Variable
Interest Entities
In June
2009, the FASB issued new accounting guidance regarding variable interest
entities (VIE’s). This new guidance is effective for annual reporting
periods beginning after November 15, 2009. This guidance requires a
qualitative analysis of which holder of a variable interest controls the VIE and
if that interest holder must consolidate a VIE. Additionally, it
requires additional disclosures and an ongoing reassessment of who must
consolidate a VIE. The Company adopted this guidance on January 1,
2010. The Company does not expect the adoption will have a material impact on
the consolidated financial statements.
Fair
Value Measurements & Disclosures
In
January 2010, the FASB issued new accounting guidance on improving disclosures
about fair market value. This guidance amends prior disclosure
requirements involving fair value measurements to add new requirements for
disclosures about transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances, and settlements relating to Level
3 measurements. The guidance also clarifies existing fair value disclosures in
regard to the level of disaggregation and about inputs and valuation techniques
used to measure fair value. The guidance also amends prior disclosure
requirements regarding postretirement benefit plan assets to require that
disclosures be provided by classes of assets instead of major categories of
assets. This guidance is effective for the first reporting period
beginning after December 15, 2009. The Company will adopt this
guidance in its first quarter 2010 reporting. The Company does not
expect the adoption will have a material impact on the consolidated financial
statements.
Critical Accounting
Policies
Management
is required to make judgments, assumptions, and estimates that affect the
amounts reported in the consolidated financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. The consolidated financial statement footnotes
describe the significant accounting policies and methods used in the preparation
of the consolidated financial statements. Certain estimates used in
the financial statements are subjective and use variables that require
judgment. These include the estimates to perform goodwill and other
asset impairments tests and to determine pension and postretirement benefit
obligations. The Company makes other estimates in the course of
accounting for unbilled revenue and the effects of regulation that are critical
to the Company’s financial results but that are less likely to be impacted by
near term changes. Other estimates that significantly affect the
Company’s results, but are not necessarily critical to operations, include
depreciating utility and nonutility plant, valuing reclamation liabilities,
valuing derivative contracts, and estimating uncollectible accounts and coal
reserves, among others. Actual results could differ from these
estimates.
Goodwill
The
Company performs an annual impairment analysis of its goodwill, all of which
resides in the Gas Utility Services operating segment, at the beginning of each
year, and more frequently if events or circumstances indicate that an impairment
loss may have been incurred. Impairment tests are performed at the
reporting unit level. The Company has determined its Gas Utility
Services operating segment as identified in Note 11 to the consolidated
financial statements to be the reporting unit. An impairment test
requires that a reporting unit’s fair value be estimated. The Company
used a discounted cash flow model and other market based information to estimate
the fair value of its Gas Utility Services operating segment, and that estimated
fair value was compared to its carrying amount, including
goodwill. The estimated fair value has been substantially in excess
of the carrying amount in each of the last three years and therefore resulted in
no impairment.
Estimating
fair value using a discounted cash flow model is subjective and requires
significant judgment in applying a discount rate, growth assumptions, company
expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment’s fair value also would have resulted in no impairment
charge.
Intercompany
Allocations
Support
Services
Vectren
provides corporate, general, and administrative services to the Company and
allocates costs to the Company, including costs for share-based compensation and
for pension and other postretirement benefits that are not directly charged to
subsidiaries. These costs have been allocated using various
allocators, including number of employees, number of customers, and/or the level
of payroll, revenue contribution, and capital
expenditures. Allocations are at cost. Management believes
that the allocation methodology is reasonable and approximates the costs that
would have been incurred had the Company secured those services on a stand-alone
basis. The allocation methodology is not subject to near term
changes.
Pension and Other
Postretirement Obligations
Vectren
satisfies the future funding requirements of its pension and other
postretirement plans and the payment of benefits from general corporate
assets. An allocation of expense, comprised of only service cost and
interest on that service cost by subsidiary, is determined based on headcount at
each measurement date. These costs are directly charged to individual
subsidiaries. Other components of costs (such as interest cost and
asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Neither plan assets nor the
ending liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. 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
obtains actuarial estimates to assess the future potential liability and funding
requirements of pension and postretirement plans. Vectren used the
following weighted average assumptions to develop 2009 periodic benefit
cost: a discount rate of 6.25 percent, an expected return on plan
assets of 8.25 percent, a rate of compensation increase of 3.75 percent, and an
inflation assumption of 3.5 percent. These key assumptions were
unchanged from the assumptions utilized in 2008. To estimate 2010
costs, the discount rate, expected return on plan assets, rate of compensation
increase, and inflation assumption were 6.0 percent, 8.0 percent, 3.5 percent,
and 3.0 percent respectively. Management currently estimates a
pension and postretirement cost of approximately $13 million in 2010, compared
to approximately $15 million in 2009, $11 million in 2008, and $14 million in
2007. Future changes in health care costs, work force demographics,
interest rates, asset values or plan changes could significantly affect the
estimated cost of these future benefits.
Management
estimates that a 50 basis point decrease in the discount rate used to estimate
2010 projected costs would generally increase periodic benefit cost by
approximately $1.6 million. A 50 basis point decrease in the discount
rate used to estimate 2009 periodic cost would have increased costs by
approximately $1.7 million.
Unbilled
Revenues
To more
closely match revenues and expenses, the Company records revenues for all gas
and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the
month to allocate unbilled units by customer class. Those allocated
units are multiplied by rates in effect during the month to calculate unbilled
revenue at balance sheet dates.
Regulation
At each
reporting date, the Company reviews current regulatory trends in the markets in
which it operates. This review involves judgment and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in FASB
guidance related to accounting for the effects of certain types of
regulation. Based on the Company’s current review, it believes its
regulatory assets are probable of recovery. If all or part of the
Company's operations cease to meet the criteria, a write off of related
regulatory assets and liabilities could be required. In addition, the
Company would be required to determine any impairment to the carrying value of
its utility plant and other regulated assets and liabilities. In the
unlikely event of a change in the current regulatory environment, such
write-offs and impairment charges could be significant.
Financial
Condition
Utility
Holdings funds the short-term and long-term financing needs of utility
operations. Vectren does not guarantee Utility Holdings’
debt. Utility Holdings’ outstanding long-term and short-term
borrowing arrangements are jointly and severally guaranteed by Indiana Gas,
SIGECO, and VEDO. The guarantees are full and unconditional and joint
and several, and Utility Holdings has no subsidiaries other than the subsidiary
guarantors. Information about the subsidiary guarantors as a group is
included in Note 14 to the consolidated financial statements. Utility
Holdings’ long-term and short-term obligations outstanding at December 31, 2009,
approximated $920 million and $16 million,
respectively. Additionally, prior to Utility Holdings’ formation,
Indiana Gas and SIGECO funded their operations separately, and therefore, have
long-term debt outstanding funded solely by their operations. SIGECO
will also occasionally issue tax exempt debt to fund qualifying pollution
control capital expenditures. Utility
Holdings’ operations have historically been the primary source for Vectren’s
common stock dividends.
The
credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas,
at December 31, 2009, are A-/Baa1 as rated by Standard and Poor's Ratings
Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s),
respectively. The credit ratings on SIGECO's secured debt are
A/A2. Utility Holdings’ commercial paper has a credit rating of
A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s
is stable. During the third quarter of 2009, Moody’s raised its
credit rating on SIGECO’s secured debt from A3 to A2; otherwise, these ratings
and outlooks did not change during 2009. A security rating is not a
recommendation to buy, sell, or hold securities. The rating is
subject to revision or withdrawal at any time, and each rating should be
evaluated independently of any other rating. Standard and Poor’s and
Moody’s lowest level investment grade rating is BBB- and Baa3,
respectively.
The
Company’s consolidated equity capitalization objective is 45-60 percent of
long-term capitalization. This objective may have varied, and will
vary, depending on particular business opportunities, capital spending
requirements, execution of long-term financing plans, and seasonal factors that
affect the Company’s operations. The Company’s equity component was
49 percent and 52 percent of long-term capitalization at December 31, 2009 and
2008, respectively. Long-term capitalization includes long-term debt,
including current maturities and debt subject to tender, as well as common
shareholders’ equity.
As of
December 31, 2009, the Company was in compliance with all financial
covenants.
Available
Liquidity in Current Credit Conditions
The
Company’s A-/Baa1 investment grade credit ratings have allowed it to access the
capital markets as needed during this period of financial market
volatility. Over the last twelve to twenty four months, the Company
has significantly enhanced its short-term borrowing capacity with the completion
of several long-term financing transactions including the issuance of long-term
debt in both 2008 and 2009 and the receipt of a $125 million capital
contribution from Vectren in 2008. The liquidity provided by these
transactions, when coupled with existing cash and expected internally generated
funds, is expected to be sufficient over the near term to fund anticipated
capital expenditures, investments, debt security redemptions, and other working
capital requirements.
Regarding
debt redemptions, there are none in 2010 and $250 million in
2011. The Company is currently considering whether to prefund a
portion of the $250 million debt redemption with a long-term debt issuance in
2010. In addition, investors have the one-time option to put $10
million in May of 2010 and a one time option to put $30 million in
2011.
Long-term
debt transactions completed in 2009 include a $100 million issuance by Utility
Holdings. SIGECO also recently remarketed $41.3 million of long-term
debt, supported by letters of credit issued under Utility Holdings' credit
facility and completed a $22.3 million tax-exempt first mortgage bond
issuance. These transactions, along with financing transactions
completed in 2008 and 2007, are more fully described below.
Consolidated Short-Term
Borrowing Arrangements
At
December 31, 2009, the Company had $520 million of short-term borrowing
capacity. As reduced by letters of credit and borrowings currently
outstanding, approximately $462 million was available. Of the $520
million in capacity, $5 million is available through June, 2010 and $515 million
is available through November, 2010.
Historically,
the Company uses short-term borrowings to supplement working capital needs and
also to fund capital investments and debt redemptions until financed on a
long-term basis. The Company has historically funded the short-term
borrowing needs of Utility Holdings’ operations through the commercial paper
market. In 2008, the Company’s access to longer term commercial paper
was significantly reduced as a result of the turmoil and volatility in the
financial markets. As a result, the Company met short-term financing needs
through a combination of A2/P2 commercial paper issuances and draws on
Utility Holdings’ $515 million commercial paper back-up credit facilities.
Throughout 2009, the Company has been able to place commercial paper without any
significant issues. However, the level of required short-term
borrowings is significantly lower compared to historical trends due to the
recently completed long-term financing transactions.
Compared
to historical trends, the Company anticipates over the next several years a
greater use of the long-term capital markets to more timely finance capital
investments and other growth as well as debt security
redemptions. This change comes as short-term borrowing arrangements
have become less certain, more volatile, and the cost of unutilized capacity is
expected to increase significantly. Thus, while the Company expects
to renew these facilities in 2010, the Company anticipates that borrowing levels
will be lower due to the reduced requirements for short-term borrowings
described above. Under current market conditions, this change is
expected to yield greater certainty to financing business operations at the
expense of some increase in interest costs.
Proceeds from Stock
Plans
Vectren
may periodically issue new common shares to satisfy dividend reinvestment plan,
stock option plan, and other employee benefit plan requirements and contribute
those proceeds to Utility Holdings. New issuances contributed to
Utility Holdings added additional liquidity of $5.8 million in 2009 and $5.3
million in 2007. In 2010, new issuances required to meet these
various plan requirements are estimated to be approximately $6 million, and such
amount is expected to be consistent with issuances in 2009.
Potential
Uses of Liquidity
Planned Capital
Expenditures
The
timing and amount of planned capital expenditures, including contractual
purchase commitments discussed below, for the five-year period 2010 - 2014 are
estimated as follows (in millions): $245 in 2010, $230 in 2011, $210
in 2012, $195 in 2013, and $215 in 2014.
Pension and Postretirement
Funding Obligations
As of
December 31, 2009, Vectren’s pension plan asset values were approximately 82
percent of the projected benefit obligation. In order to increase the
funded status, Vectren’s management currently estimates the qualified pension
plans require contributions of $12 million in 2010. Under current
market conditions, Vectren estimates similar funding in 2011, a portion which
may be funded by Utility Holdings. During 2009, Vectren made
contributions of approximately $34 million to qualified pension plans, of which
approximately $30 million was funded by Utility Holdings. In addition
to the qualified plan funding, Vectren anticipates payments totaling $20 million
in 2010 associated with its other retirement and deferred compensation plans, of
which the majority is expected to be funded by Utility Holdings.
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2009:
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
||||||||||||||||||||||
|
Long-term
debt (1)
|
$ | 1,306.1 | $ | - | $ | 250.0 | $ | - | $ | 105.0 | $ | - | $ | 951.1 | ||||||||||||||
|
Short-term
debt
|
16.4 | 16.4 | - | - | - | - | - | |||||||||||||||||||||
|
Long-term
debt interest commitments
|
1,072.7 | 77.5 | 76.2 | 61.0 | 58.6 | 55.4 | 744.0 | |||||||||||||||||||||
|
Plant
& commodity purchase commitments
|
16.5 | - | - | 5.3 | 5.5 | 5.7 | - | |||||||||||||||||||||
|
Operating
leases
|
1.7 | 0.5 | 0.4 | 0.3 | 0.3 | 0.2 | - | |||||||||||||||||||||
|
Total
(2)
|
$ | 2,413.4 | $ | 94.4 | $ | 326.6 | $ | 66.6 | $ | 169.4 | $ | 61.3 | $ | 1,695.1 | ||||||||||||||
|
(1)
|
Certain
long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions
allow holders the one-time option to put debt back to the Company at face
value or the Company to call debt at face value or at a
premium. Long-term debt subject to tender during the years
following 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012
and thereafter.
|
|
(2)
|
The
Company has other long-term liabilities that total approximately $91
million. This amount is comprised of the
following: deferred compensation and share-based compensation
$28 million, asset retirement obligations $30 million, pension and
postretirement obligations $11 million, investment tax credits $6 million,
environmental remediation $6 million, and other obligations including
unrecognized tax benefits totaling $10 million. Based on the
nature of these items their expected settlement dates cannot be
estimated.
|
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase natural gas, coal, and electricity as well as certain transportation
and storage rights. Costs arising from these commitments, while
significant, are pass-through costs, generally collected dollar-for-dollar from
retail customers through regulator-approved cost recovery
mechanisms. Because of the pass through nature of these costs, they
have not been included in the listing of contractual obligations.
Off Balance Sheet
Arrangements
As of
December 31, 2009, other than the letters of credit discussed above, the Company
does not have any material off balance sheet arrangements.
Comparison of Historical
Sources & Uses of Liquidity
The
Company's primary source of liquidity to fund working capital requirements has
been cash generated from operations, which totaled $356.8 million in 2009,
compared to $435.0 million in 2008 and $232.2 million in 2007.
The $78.2
million decrease occurring in 2009 compared to 2008 was primarily due to changes
in working capital, which reduced operating cash flow approximately $60.1
million. This decrease is caused by the timing of intercompany tax
transactions and the timing of natural gas inventory sales and purchases due to
exiting the merchant function in the Ohio service territory in October of
2008. In addition, the Company made increased contributions to
Vectren’s pension and other retirement plans during 2009. These
impacts have been partially offset by a $31.8 million increase in net income
before the impacts of depreciation, deferred taxes, and other non-cash
charges. Tax payments in both 2009 and 2008 were favorably impacted
by federal stimulus plans authorizing bonus depreciation and IRS approval in
2009 to change its tax method for recognizing repair and maintenance
activities.
In 2008
cash flow from operating activities increased $202.8 million compared to
2007. Working capital changes generated cash of $71.5 million in 2008
compared to cash used of $33.7 million in 2007. The increase in cash
from working capital results primarily from the permanent reduction of natural
gas inventory associated with VEDO’s exit of the merchant function, offset by
growth in recoverable fuel balances. Higher levels of deferred taxes
due primarily to federal stimulus plans authorizing bonus depreciation on
qualifying capital expenditures increased cash flow approximately $40.3
million. The remaining increase in operating cash flow is primarily
due to the cash collection of previously deferred regulatory assets and higher
earnings and depreciation.
Financing Cash
Flow
Although
working capital requirements are generally funded by cash flow from operations,
the Company uses short-term borrowings to supplement working capital needs when
accounts receivable balances are at their highest and gas storage is
refilled. Additionally, short-term borrowings are required for
capital projects and investments until they are financed on a long-term
basis.
During
2009 and 2008, net cash flow associated with financing activities is reflective
of management’s ongoing effort to rely less on short-term borrowing
arrangements. The Company’s 2009 and 2008 operating cash flow funded
over 90 percent of capital expenditures and dividends in those
years. Recently completed long-term financing transactions have
allowed for the repayment of nearly $370 million in short term borrowings over
the past two years. In addition, these long-term financing
transactions have financed other capital expenditures on a long-term
basis. During the first quarter of 2008, the Company mitigated its
exposure to auction rate debt markets. These transactions are more
fully described below.
Utility
Holdings 2009 Debt Issuance
On April
7, 2009, Utility Holdings entered into a private placement Note Purchase
Agreement pursuant to which institutional investors purchased from Utility
Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020
(2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’
three utilities: SIGECO, Indiana Gas, and VEDO. These
guarantees are full and unconditional and joint and several. The
proceeds from the sale of the 2020 Notes, net of issuance costs, totaled
approximately $99.5 million.
The 2020
Notes have no sinking fund requirements, and interest payments are due
semi-annually. The 2020 Notes contain customary representations,
warranties and covenants, including a leverage covenant consistent with leverage
covenants contained in the Utility Holdings’ $515 million short-term credit
facility.
SIGECO
2009 Debt Issuance
On August
19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond
issuance at an interest rate of 5.4 percent that is fixed through
maturity. The bonds mature in 2040. The proceeds from the
sale of the bonds, net of issuance costs, totaled approximately $21.3
million.
Capital
Contribution from Vectren
On June
27, 2008, Vectren physically settled an equity forward agreement associated with
a 2007 public offering of its common stock. Vectren transferred net
proceeds of approximately $124.8 million to Utility Holdings, and Utility
Holdings used the proceeds to repay short-term debt obligations incurred
primarily to fund its capital expenditure program. The proceeds received
were recorded as an increase to Common Stock in Common
Shareholder’s Equity and are presented in the Statement of Cash Flows as a
financing activity.
Additional
Capital Contributions
In
addition to the $124.8 million capital contribution above, during the years
ended December 31, 2009, 2008,and 2007, the Company has cumulatively
received additional capital of $12.2 million from Vectren, funded by new share
issues from Vectren’s dividend reinvestment plan.
Utility
Holdings 2008 Debt Issuance
In March
2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured
notes due April 1, 2039 (2039 Notes) at par. The 2039 Notes are
guaranteed by Utility Holdings’ three public utilities: SIGECO,
Indiana Gas, and VEDO. These guarantees are full and unconditional
and joint and several.
The 2039
Notes have no sinking fund requirements, and interest payments are due
monthly. The notes may be called by Utility Holdings, in whole or in
part, at any time on or after April 1, 2013, at 100 percent of principal amount
plus accrued interest. During 2007, Utility Holdings entered into
several interest rate hedges with an $80 million notional
amount. Upon issuance of the notes, these instruments were settled
resulting in the payment of approximately $9.6 million, which was recorded as a
Regulatory asset
pursuant to existing regulatory orders. The value paid is being
amortized as an increase to interest expense over the life of the
issue. The proceeds from the sale of the 2039 Notes less settlement
of the hedging arrangements and payments of issuance costs amounted to
approximately $111.1 million.
Auction
Rate Securities
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt had a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate was to reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation (Ambac).
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax-exempt auction rate mode long-term debt, including the $17
million issued in December 2007, of its plans to convert that debt from its
current auction rate mode into a daily interest rate mode. In March
2008, the debt was tendered at 100 percent of the principal amount plus accrued
interest. During March 2008, SIGECO remarketed approximately $61.8
million of these instruments at interest rates that are fixed to maturity,
receiving proceeds, net of issuance costs, of approximately $60.0
million. The terms are $22.6 million at 5.15 percent due in 2023,
$22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due
in 2041.
On March
26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations,
receiving proceeds, net of issuance costs of approximately $40.6
million. The remarketed notes have a variable rate interest rate
which is reset weekly and are supported by a standby letter of credit backed by
Utility Holdings’ $515 million short-term credit facility. The notes
are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015
and $31.5 million are due in 2025. The initial interest rate paid to
investors was 0.55 percent. The equivalent rate of the debt at
inception, inclusive of interest, weekly remarketing fees, and letter of credit
fees, approximated 1 percent. Since Utility Holdings’ short-term
facility has a remaining term of less than one year, these obligations are
classified as Long-term debt
subject to tender in current liabilities.
Long-Term
Debt Put and Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. Other than certain instruments that
can be put to the company upon the death of the holder (death puts), these put
or call provisions are not triggered by specific events, but are based upon
dates stated in the note agreements. During 2009 and 2008, the
Company repaid approximately $3.0 million and $1.6 million, respectively,
related to death puts. In 2007, no debt was put to the
Company. Debt which may be put to the Company for reasons other than
a death during the years following 2009 (in millions) is $10.0 in 2010, $30.0 in
2011, zero in 2012 and thereafter.
Investing Cash
Flow
Cash flow
required for investing activities was $310.3 million in 2009, $308.3 million in
2008, and $303.3 million in 2007. Capital expenditures are the
primary component of investing activities and totaled $306.9 million in 2009,
compared to $306.3 million in 2008 and $302.5 million in
2007. Capital expenditures in 2009 include the impact of the January
2009 ice storm that resulted in approximately $20 million in capital
expenditures. The year ended December 31, 2008 includes increased
capital expenditures for environmental compliance equipment, compared to
2007. Both 2009 and 2008 include increased capital expenditures for
bare steel cast iron replacement programs and other expenditures qualifying for
federal bonus deprecation.
Forward-Looking
Information
A
“safe harbor” for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The
Reform Act of 1995 was adopted to encourage such forward-looking statements
without the threat of litigation, provided those statements are identified as
forward-looking and are accompanied by meaningful cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Certain matters
described in Management’s Discussion and Analysis of Results of Operations and
Financial Condition are forward-looking statements. Such statements
are based on management’s beliefs, as well as assumptions made by and
information currently available to management. When used in this
filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”,
“objective”, “projection”, “forecast”, “goal”, “likely”, and similar expressions
are intended to identify forward-looking statements. In addition to
any assumptions and other factors referred to specifically in connection with
such forward-looking statements, factors that could cause the Company’s actual
results to differ materially from those contemplated in any forward-looking
statements include, among others, the following:
|
·
|
Factors
affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
transportation and storage costs, or availability due to higher demand,
shortages, transportation problems or other developments; environmental or
pipeline incidents; transmission or distribution incidents; unanticipated
changes to electric energy supply costs, or availability due to demand,
shortages, transmission problems or other developments; or electric
transmission or gas pipeline system
constraints.
|
|
·
|
Catastrophic
events such as fires, earthquakes, explosions, floods, ice storms,
tornados, terrorist acts or other similar occurrences could adversely
affect Vectren’s facilities, operations, financial condition and results
of operations.
|
|
·
|
Increased
competition in the energy industry, including the effects of industry
restructuring and unbundling.
|
|
·
|
Regulatory
factors such as unanticipated changes in rate-setting policies or
procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate
increases.
|
|
·
|
Financial,
regulatory or accounting principles or policies imposed by the Financial
Accounting Standards Board; the Securities and Exchange Commission; the
Federal Energy Regulatory Commission; state public utility commissions;
state entities which regulate electric and natural gas transmission and
distribution, natural gas gathering and processing, electric power supply;
and similar entities with regulatory
oversight.
|
|
·
|
Economic
conditions including the effects of an economic downturn, inflation rates,
commodity prices, and monetary
fluctuations.
|
|
·
|
Economic
conditions surrounding the recent recession, which may be more
prolonged and more severe than cyclical downturns, including significantly
lower levels of economic activity; uncertainty regarding energy prices and
the capital and commodity markets; decreases in demand for natural gas and
electricity; impacts on both gas and electric large customers; lower
residential and commercial customer counts; and higher operating
expenses.
|
|
·
|
Increased
natural gas and coal commodity prices and the potential impact on customer
consumption, uncollectible accounts expense, unaccounted for gas and
interest expense.
|
|
·
|
Changing
market conditions and a variety of other factors associated with physical
energy and financial trading activities including, but not limited to,
price, basis, credit, liquidity, volatility, capacity, interest rate, and
warranty risks.
|
|
·
|
Direct
or indirect effects on the Company’s business, financial condition,
liquidity and results of operations resulting from changes in credit
ratings, changes in interest rates, and/or changes in market perceptions
of the utility industry and other energy-related
industries.
|
|
·
|
Employee
or contractor workforce factors including changes in key executives,
collective bargaining agreements with union employees, aging workforce
issues, work stoppages, or pandemic
illness.
|
|
·
|
Legal
and regulatory delays and other obstacles associated with mergers,
acquisitions and investments in joint
ventures.
|
|
·
|
Costs,
fines, penalties and other effects of legal and administrative
proceedings, settlements, investigations, claims, including, but not
limited to, such matters involving compliance with state and federal laws
and interpretations of these laws.
|
|
·
|
Changes
in or additions to federal, state or local legislative
requirements, such as changes in or additions to tax laws or rates,
environmental laws, including laws governing greenhouse gases, mandates of
sources of renewable energy, and other
regulations.
|
|
·
|
The
performance of projects undertaken by Vectren’s nonutility businesses and
the success of efforts to invest in and develop new opportunities,
including but not limited to, the Company’s coal mining, gas marketing,
and energy infrastructure
strategies.
|
The
Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM
7A. QUALITATIVE & QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK
The
Company is exposed to various business risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures
are monitored and managed by the Company as an integral part of its overall risk
management program. The Company’s risk management program includes,
among other things, the use of derivatives. The Company may also
execute derivative contracts in the normal course of operations while buying and
selling commodities to be used in operations and optimizing its generation
assets.
|
The
Company has in place a risk management committee that consists of senior
management as well as financial and operational management. The
committee is actively involved in identifying risks as well as reviewing
and authorizing risk mitigation
strategies.
|
Commodity
Price Risk
Regulated
Operations
The
Company’s regulated operations have limited exposure to commodity price risk for
transactions involving purchases and sales of natural gas, coal and purchased
power for the benefit of retail customers due to current state regulations,
which subject to compliance with those regulations, allow for recovery of the
cost of such purchases through natural gas and fuel cost adjustment
mechanisms. Constructive regulatory orders, such as those authorizing
lost margin recovery, other innovative rate designs, and recovery of unaccounted
for gas and other gas related expenses, also mitigate the effect volatile gas
costs may have on the Company’s financial condition. Although
Vectren’s regulated operations are exposed to limited commodity price risk,
volatile natural gas prices have other effects on working capital requirements,
interest costs, and some level of price-sensitivity in volumes sold or
delivered.
Wholesale Power
Marketing
The
Company’s wholesale power marketing activities undertake strategies to optimize
electric generating capacity beyond that needed for native load. In
recent years, the primary strategy involves the sale of excess generation into
the MISO Day Ahead and Real-time markets. As part of these
strategies, the Company may also from time to time execute energy contracts that
commit the Company to purchase and sell electricity in future
periods. Commodity price risk results from forward positions that
commit the Company to deliver electricity. The Company mitigates
price risk exposure with planned unutilized generation capability and
occasionally offsetting forward purchase contracts. The Company
accounts for any energy contracts that are derivatives at fair value with the
offset marked to market through earnings. No market sensitive
derivative positions were outstanding on December 31, 2009 and
2008.
For
retail sales of electricity, the Company receives the majority of its NOx and
SO2
allowances at zero cost through an allocation process. Based
on arrangements with regulators, wholesale operations can purchase allowances
from retail operations at current market values, the value of which is
distributed back to retail customers through a MISO cost recovery tracking
mechanism. Wholesale operations are therefore at risk for the cost of
allowances, which for the recent past have been volatile. The Company
manages this risk by purchasing allowances from retail operations as needed and
occasionally from other third parties in advance of usage. In the
past, the Company also used derivative financial instruments to hedge this risk,
but no such derivative instruments were outstanding at December 31, 2009 or
2008.
Interest
Rate Risk
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on interest
expense. The Company manages this risk by allowing an annual average
of 20 percent and 30 percent of its total debt to be exposed to variable rate
volatility. However, this targeted range may be exceeded during the
seasonal increases in short-term borrowing. To manage this exposure,
the Company may use derivative financial instruments.
Market
risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2009 and 2008, the weighted average
combined borrowings under these arrangements approximated $60 million and $278
million, respectively. At December 31, 2009 and 2008, combined
borrowings under these arrangements were $58 million and $192 million,
respectively. Based upon average borrowing rates under these
facilities during the years ended December 31, 2009 and 2008, an increase of 100
basis points (one percentage point) in the rates would have increased interest
expense by $0.6 million and $2.8 million, respectively.
Other
Risks
By using
financial instruments to manage risk, the Company creates exposure to
counter-party credit risk and market risk. The Company manages
exposure to counter-party credit risk by entering into contracts with companies
that can be reasonably expected to fully perform under the terms of the
contract. Counter-party credit risk is monitored regularly and
positions are adjusted appropriately to manage risk. Further, tools
such as netting arrangements and requests for collateral are also used to manage
credit risk. Market risk is the adverse effect on the value of a
financial instrument that results from a change in commodity prices or interest
rates. The Company attempts to manage exposure to market risk
associated with commodity contracts and interest rates by establishing
parameters and monitoring those parameters that limit the types and degree of
market risk that may be undertaken.
The
Company’s customer receivables from gas and electric sales and gas
transportation services are primarily derived from residential, commercial, and
industrial customers located in Indiana and west central Ohio. The
Company manages credit risk associated with its receivables by continually
reviewing creditworthiness and requests cash deposits or refunds cash deposits
based on that review. Credit risk associated with certain investments
is also managed by a review of creditworthiness and receipt of
collateral. In addition, credit risk is mitigated by regulatory
orders that allow recovery of all uncollectible accounts expense in Ohio and the
gas cost portion of uncollectible accounts expense in Indiana based on
historical experience.
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S RESPONSIBILITY
FOR THE FINANCIAL STATEMENTS
Vectren
Utility Holdings, Inc.’s management is responsible for establishing and
maintaining adequate internal control over financial reporting. Those
control procedures underlie the preparation of the consolidated balance sheets,
statements of income, cash flows, and common shareholder’s equity, and related
footnotes contained herein.
These
consolidated financial statements were prepared in conformity with accounting
principles generally accepted in the United States and follow accounting
policies and principles applicable to regulated public utilities. The
integrity and objectivity of these consolidated financial statements, including
required estimates and judgments, is the responsibility of
management.
These
consolidated financial statements are also subject to an evaluation of internal
control over financial reporting conducted under the supervision and with the
participation of management, including the Chief Executive Officer and Chief
Financial Officer. Based on that evaluation, conducted under the
framework in Internal Control
— Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission, the Company concluded that its
internal control over financial reporting was effective as of December 31,
2009. Management certified this in its Sarbanes Oxley Section 302
certifications, which are attached as exhibits to this 2009 Form
10-K.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the 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, 2009 and
2008, and the related consolidated statements of income, common shareholder’s
equity and cash flows for each of the three years in the period ended December
31, 2009. Our audits also included the financial statement schedule included in
the Index at Item 15. These financial statements and financial statement
schedule are the responsibility of the Company’s management. Our
responsibility is to express an opinion on the financial statements and
financial statement schedule based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In
our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Vectren Utility Holdings, Inc. and
subsidiaries as of December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2009, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
/s/
DELOITTE & TOUCHE LLP
Indianapolis,
Indiana
March 5,
2010
VECTREN
UTILITY HOLDINGS. INC. AND SUBSIDIARY COMPANIES
|
|
CONSOLIDATED
BALANCE SHEETS
|
(In
millions)
|
At December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash
& cash equivalents
|
$ | 6.2 | $ | 52.5 | ||||
|
Accounts
receivable - less reserves of $4.0 &
|
||||||||
|
$4.5,
respectively
|
108.1 | 164.0 | ||||||
|
Receivables
due from other Vectren companies
|
0.7 | 4.7 | ||||||
|
Accrued
unbilled revenues
|
115.4 | 167.2 | ||||||
|
Inventories
|
127.9 | 84.6 | ||||||
|
Recoverable
fuel & natural gas costs
|
- | 3.1 | ||||||
|
Prepayments
& other current assets
|
69.2 | 103.1 | ||||||
|
Total
current assets
|
427.5 | 579.2 | ||||||
|
Utility
Plant
|
||||||||
|
Original
cost
|
4,601.4 | 4,335.3 | ||||||
|
Less: accumulated
depreciation & amortization
|
1,722.6 | 1,615.0 | ||||||
|
Net
utility plant
|
2,878.8 | 2,720.3 | ||||||
|
Investments
in unconsolidated affiliates
|
0.2 | 0.2 | ||||||
|
Other
investments
|
31.4 | 24.1 | ||||||
|
Nonutility
plant - net
|
171.8 | 182.4 | ||||||
|
Goodwill
- net
|
205.0 | 205.0 | ||||||
|
Regulatory
assets
|
104.1 | 115.7 | ||||||
|
Other
assets
|
4.3 | 11.2 | ||||||
|
TOTAL
ASSETS
|
$ | 3,823.1 | $ | 3,838.1 | ||||
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,
|
||||||||
|
2009
|
2008
|
|||||||
|
LIABILITIES & SHAREHOLDER'S
EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Accounts
payable
|
$ | 133.1 | $ | 212.5 | ||||
|
Accounts
payable to affiliated companies
|
54.1 | 72.8 | ||||||
|
Payables
to other Vectren companies
|
53.6 | 69.0 | ||||||
|
Refundable
fuel & natural gas costs
|
22.3 | 4.1 | ||||||
|
Accrued
liabilities
|
131.4 | 147.7 | ||||||
|
Short-term
borrowings
|
16.4 | 191.9 | ||||||
|
Long-term
debt subject to tender
|
51.3 | 80.0 | ||||||
|
Total
current liabilities
|
462.2 | 778.0 | ||||||
|
Long-Term
Debt - Net of Current Maturities &
|
||||||||
|
Debt
Subject to Tender
|
1,254.8 | 1,065.1 | ||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||
|
Deferred
income taxes
|
418.0 | 332.1 | ||||||
|
Regulatory
liabilities
|
322.2 | 315.1 | ||||||
|
Deferred
credits & other liabilities
|
91.2 | 104.9 | ||||||
|
Total
deferred credits & other liabilities
|
831.4 | 752.1 | ||||||
|
Commitments
& Contingencies (Notes 10 - 12)
|
||||||||
|
Common
Shareholder's Equity
|
||||||||
|
Common
stock (no par value)
|
769.9 | 763.0 | ||||||
|
Retained
earnings
|
504.7 | 479.8 | ||||||
|
Accumulated
other comprehensive income
|
0.1 | 0.1 | ||||||
|
Total
common shareholder's equity
|
1,274.7 | 1,242.9 | ||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,823.1 | $ | 3,838.1 | ||||
|
|
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,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
OPERATING
REVENUES
|
||||||||||||
|
Gas
utility
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Electric
utility
|
528.6 | 524.2 | 487.9 | |||||||||
|
Other
|
1.6 | 1.8 | 1.7 | |||||||||
|
Total
operating revenues
|
1,596.2 | 1,958.7 | 1,759.0 | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||
|
Cost
of gas sold
|
618.1 | 983.1 | 847.2 | |||||||||
|
Cost
of fuel & purchased power
|
194.3 | 182.9 | 174.8 | |||||||||
|
Other
operating
|
304.6 | 300.3 | 266.1 | |||||||||
|
Depreciation
& amortization
|
180.9 | 165.5 | 158.4 | |||||||||
|
Taxes
other than income taxes
|
60.3 | 72.3 | 68.1 | |||||||||
|
Total
operating expenses
|
1,358.2 | 1,704.1 | 1,514.6 | |||||||||
|
OPERATING
INCOME
|
238.0 | 254.6 | 244.4 | |||||||||
|
Other
income - net
|
7.8 | 4.0 | 9.4 | |||||||||
|
Interest
expense
|
79.2 | 79.9 | 80.6 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
166.6 | 178.7 | 173.2 | |||||||||
|
Income
taxes
|
59.2 | 67.6 | 66.7 | |||||||||
|
NET
INCOME
|
$ | 107.4 | $ | 111.1 | $ | 106.5 | ||||||
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,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
| Net income | $ 107.4 | $ 111.1 | $ 106.5 | |||||||||
|
Adjustments
to reconcile net income to cash from operating activities:
|
||||||||||||
|
Depreciation
& amortization
|
180.9 | 165.5 | 158.4 | |||||||||
|
Deferred
income taxes & investment tax credits
|
76.2 | 54.7 | 14.4 | |||||||||
|
Expense
portion of pension & postretirement periodic benefit
cost
|
4.1 | 2.6 | 4.1 | |||||||||
|
Provision
for uncollectible accounts
|
14.6 | 15.8 | 15.0 | |||||||||
|
Other
non-cash expense - net
|
14.0 | 15.7 | 7.6 | |||||||||
|
Changes
in working capital accounts:
|
||||||||||||
|
Accounts
receivable, including to Vectren companies
|
||||||||||||
|
&
accrued unbilled revenue
|
93.1 | (56.1 | ) | (54.1 | ) | |||||||
|
Inventories
|
(43.2 | ) | 46.8 | 7.0 | ||||||||
|
Recoverable/refundable
fuel & natural gas costs
|
21.3 | (26.2 | ) | (6.3 | ) | |||||||
|
Prepayments
& other current assets
|
48.1 | (13.4 | ) | 4.0 | ||||||||
|
Accounts
payable, including to Vectren companies
|
||||||||||||
|
&
affiliated companies
|
(95.9 | ) | 96.2 | 14.6 | ||||||||
|
Accrued
liabilities
|
(12.0 | ) | 24.2 | 1.1 | ||||||||
|
Changes
in noncurrent assets
|
1.7 | 20.6 | (22.3 | ) | ||||||||
|
Changes
in noncurrent liabilities
|
(53.5 | ) | (22.5 | ) | (17.8 | ) | ||||||
|
Net
cash flows from operating activities
|
356.8 | 435.0 | 232.2 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds
from:
|
||||||||||||
|
Long-term
debt - net of issuance costs & hedging proceeds
|
161.3 | 171.1 | 16.3 | |||||||||
|
Additional
capital contribution
|
6.9 | 124.8 | 5.3 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Dividends
to parent
|
(82.5 | ) | (83.2 | ) | (76.6 | ) | ||||||
|
Retirement
of long-term debt
|
(3.0 | ) | (104.6 | ) | (6.5 | ) | ||||||
|
Net
change in short-term borrowings, including from other
|
||||||||||||
|
Vectren
companies
|
(175.5 | ) | (194.0 | ) | 115.8 | |||||||
|
Net
cash flows from financing activities
|
(92.8 | ) | (85.9 | ) | 54.3 | |||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds
from other investing activities
|
0.2 | 2.5 | 1.0 | |||||||||
|
Requirements
for:
|
||||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(306.9 | ) | (306.3 | ) | (302.5 | ) | ||||||
|
Other
investments
|
(3.6 | ) | (4.5 | ) | (1.8 | ) | ||||||
|
Net
cash flows from investing activities
|
(310.3 | ) | (308.3 | ) | (303.3 | ) | ||||||
|
Net
change in cash & cash equivalents
|
(46.3 | ) | 40.8 | (16.8 | ) | |||||||
|
Cash
& cash equivalents at beginning of period
|
52.5 | 11.7 | 28.5 | |||||||||
|
Cash
& cash equivalents at end of period
|
$ | 6.2 | $ | 52.5 | $ | 11.7 | ||||||
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
|
Total
|
|||||||||||||
|
Balance
at January 1, 2007
|
$ | 632.9 | $ | 422.9 | $ | 0.9 | $ | 1,056.7 | ||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
106.5 | 106.5 | ||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
Unrealized
losses - net of $0.1 million in tax
|
0.1 | 0.1 | ||||||||||||||
|
Reclassification
to net income - net of $0.4 million in tax
|
(0.7 | ) | (0.7 | ) | ||||||||||||
|
Total
comprehensive income
|
105.9 | |||||||||||||||
|
Adoption
of FIN 48
|
(0.9 | ) | (0.9 | ) | ||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
5.3 | 5.3 | ||||||||||||||
|
Dividends
|
(76.6 | ) | (76.6 | ) | ||||||||||||
|
Balance
at December 31, 2007
|
638.2 | 451.9 | 0.3 | 1,090.4 | ||||||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
111.1 | 111.1 | ||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
Reclassification
to net income - net of $0.2 million in tax
|
(0.2 | ) | (0.2 | ) | ||||||||||||
|
Total
comprehensive income
|
110.9 | |||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
124.8 | 124.8 | ||||||||||||||
|
Dividends
|
(83.2 | ) | (83.2 | ) | ||||||||||||
|
Balance
at December 31, 2008
|
763.0 | 479.8 | 0.1 | 1,242.9 | ||||||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income & total comprehensive income
|
107.4 | 107.4 | ||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Additional
capital contribution
|
6.9 | 6.9 | ||||||||||||||
|
Dividends
|
(82.5 | ) | (82.5 | ) | ||||||||||||
|
Balance
at December 31, 2009
|
$ | 769.9 | $ | 504.7 | $ | 0.1 | $ | 1,274.7 | ||||||||
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
& Nature of Operations
|
Vectren
Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana
corporation, was formed on March 31, 2000, to serve as the intermediate holding
company for Vectren Corporation’s (Vectren) three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North),
Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the
Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has
other assets that provide information technology and other services to the three
utilities. Vectren, an Indiana corporation, is an energy holding
company headquartered in Evansville, Indiana, and was organized on June 10,
1999. Both Vectren and Utility Holdings are holding companies as
defined by the Energy Policy Act of 2005 (Energy Act).
Indiana
Gas provides energy delivery services to over 567,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 111,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation assets to serve its electric
customers and optimizes those assets in the wholesale power
market. Indiana Gas and SIGECO generally do business as Vectren
Energy Delivery of Indiana. The Ohio operations provide energy
delivery services to approximately 315,000 natural gas customers located near
Dayton in west central Ohio. The Ohio operations are owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly
owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47
percent ownership). The Ohio operations generally do business as
Vectren Energy Delivery of Ohio.
|
2.
|
Summary
of Significant Accounting Policies
|
In
applying its accounting policies, the Company makes judgments, assumptions, and
estimates that affect the amounts reported in these consolidated financial
statements and related footnotes. Examples of transactions for which
estimation techniques are used include valuing pension and postretirement
benefit obligations, unbilled revenue, uncollectible accounts, regulatory assets
and liabilities, reclamation liabilities, and derivatives and other financial
instruments. Estimates also impact the depreciation of utility and
nonutility plant and the testing goodwill and other assets for
impairment. Recorded estimates are revised when better information
becomes available or when actual amounts can be determined. Actual
results could differ from current estimates.
Principles of
Consolidation
The
consolidated financial statements include the accounts of the Company and its
wholly owned subsidiaries, after elimination of significant intercompany
transactions.
Subsequent Events
Review
Management
performs a review of subsequent events for any events occurring after the
balance sheet date but prior to the date the financial statements are
issued.
Cash & Cash
Equivalents
All
highly liquid investments with an original maturity of three months or less at
the date of purchase are considered cash equivalents. Cash and cash
equivalents are stated at cost plus accrued interest to approximate fair
value.
Revenues
Revenues
are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.
Excise & Utility
Receipts Taxes
Excise
taxes and a portion of utility receipts taxes are included in rates charged to
customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $36.2 million in 2009, $44.9
million in 2008, and $41.8 million in 2007. Expense associated with
excise and utility receipts taxes are recorded as a component of Taxes other than income
taxes.
Inventories
Inventories consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Gas
in storage – at LIFO cost
|
$ | 24.4 | $ | 22.2 | ||||
|
Gas
in storage – at average cost
|
- | 0.4 | ||||||
|
Total
Gas in storage
|
24.4 | 22.6 | ||||||
|
Materials
& supplies
|
35.0 | 31.9 | ||||||
|
Fuel
(coal & oil) for electric generation
|
66.8 | 28.4 | ||||||
|
Other
|
1.7 | 1.7 | ||||||
|
Total
inventories
|
$ | 127.9 | $ | 84.6 | ||||
Based on the average cost of gas purchased during December, the cost of replacing gas in stoarge carried at LIFO cost exceeded that carrying value at December 31, 2009, and 2008, by approximately $19 million and $35 million, respectively. All other inventories are carried at average cost.
Plant, Property, &
Equipment
Both the
Company’s Utility Plant
and Nonutility Plant is
stated at historical cost, inclusive of financing costs and direct and indirect
construction costs, less accumulated depreciation and when necessary, impairment
charges. The cost of renewals and betterments that extend the useful
life are capitalized. Maintenance and repairs, including the cost of
removal of minor items of property and planned major maintenance projects, are
charged to expense as incurred.
Impairment
Reviews
Property,
plant and equipment along with other long-lived assets are reviewed as facts and
circumstances indicate that the carrying amount may be impaired. This
impairment review involves the comparison of an asset’s (or group of assets’)
carrying value to the estimated future cash flows the asset (or asset group) is
expected to generate over a remaining life. If this evaluation were
to conclude that the carrying value is impaired, an impairment charge would be
recorded based on the difference between the carrying amount and its fair value
(less costs to sell for assets to be disposed of by sale) as a charge to
operations or discontinued operations.
Utility
Plant & Related Depreciation
Both the
IURC and PUCO allow the Company’s utilities to capitalize financing costs
associated with Utility
Plant based on a computed interest cost and a designated cost of equity
funds. These financing costs are commonly referred to as AFUDC and
are capitalized for ratemaking purposes and for financial reporting purposes
instead of amounts that would otherwise be capitalized when acquiring nonutility
plant. The Company reports both the debt and equity components of
AFUDC in Other – net in
the Consolidated Statements of
Income.
When
property that represents a retirement unit is replaced or removed, the remaining
historical value of such property is charged to Utility plant, with an
offsetting charge to Accumulated depreciation,
resulting in no gain or loss. Costs to dismantle and remove retired
property are recovered through the depreciation rates as determined by the IURC
and PUCO.
The
Company’s portion of jointly owned Utility Plant, along with
that plant’s related operating expenses, is presented in these financial
statements in proportion to the ownership percentage.
Nonutility
Plant & Related Depreciation
The
depreciation of Nonutility
Plant is charged against income over its estimated useful life, using the
straight-line method of depreciation. When nonutility property is
retired, or otherwise disposed of, the asset and accumulated depreciation are
removed, and the resulting gain or loss is reflected in income, typically
impacting operating expenses.
Goodwill
Goodwill recorded on the
Consolidated Balance
Sheets results from business acquisitions and is based on a fair value
allocation of the businesses’ purchase price at the time of
acquisition. Goodwill is charged to expense only when it is
impaired. The Company tests its goodwill for impairment at a
reporting unit level at least annually and that test is performed at the
beginning of each year. Impairment reviews consist of a comparison of
the fair value of a reporting unit to its carrying amount. If the
fair value of a reporting unit is less than its carrying amount, an impairment
loss is recognized in operations. Through December 31, 2009, no
goodwill impairments have been recorded. All of the Company’s
goodwill is included in the Gas Utility Services operating segment.
Intangible
Assets
The
Company has emission allowances relating to its wholesale power marketing
operations totaling $1.3 million and $1.6 million at December 31, 2009 and 2008,
respectively. The value of the emission allowances are recognized as
they are consumed or sold.
Regulation
Retail
public utility operations affecting Indiana customers are subject to regulation
by the IURC, and retail public utility operations affecting Ohio customers are
subject to regulation by the PUCO. The Company’s accounting policies
give recognition to the ratemaking and accounting practices authorized by these
agencies.
Refundable
or Recoverable Gas Costs & Cost of Fuel & Purchased Power
All
metered gas rates contain a gas cost adjustment clause that allows the Company
to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel. The net
energy cost of purchased power, subject to a variable benchmark based on NYMEX
natural gas prices, is also recovered through regulatory
proceedings. The Company records any under-or-over-recovery resulting
from gas and fuel adjustment clauses each month in revenues. A
corresponding asset or liability is recorded until the under or over-recovery is
billed or refunded to utility customers. The cost of gas sold is
charged to operating expense as delivered to customers, and the cost of fuel and
purchased power for electric generation is charged to operating expense when
consumed.
Regulatory
Assets & Liabilities
Regulatory
assets represent probable future revenues associated with certain incurred
costs, which will be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable expenditures by
the Company for removal costs or future reductions in revenues associated with
amounts that are to be credited to customers through the ratemaking
process. The Company continually assesses the recoverability of costs
recognized as regulatory assets and liabilities and the ability to recognize new
regulatory assets and liabilities associated with its regulated utility
operations. Given the current regulatory environment in its
jurisdictions, the Company believes such accounting is appropriate.
The
Company collects an estimated cost of removal of its utility plant through
depreciation rates established in regulatory proceedings. The Company
records amounts expensed in advance of payments as a Regulatory liability because
the liability does not meet the threshold of an asset retirement
obligation.
Asset Retirement
Obligations
A portion
of removal costs related to interim retirements of gas utility pipeline and
utility poles, certain asbestos-related issues, and reclamation activities meet
the definition of an asset retirement obligation (ARO). The Company
records the fair value of a liability for a legal ARO in the period in which it
is incurred. When the liability is initially recorded, the Company
capitalizes a cost by increasing the carrying amount of the related long-lived
asset. The liability is accreted, and the capitalized cost is
depreciated over the useful life of the related asset. Upon
settlement of the liability, the Company settles the obligation for its recorded
amount or incurs a gain or loss. To the extent regulation is
involved, regulatory assets and liabilities result when accretion and
amortization is adjusted to match rates established by regulators and any gain
or loss is subject to deferral.
ARO’s
included in Other
liabilities total $29.9 million and $24.7 million at December 31, 2009
and 2008, respectively. ARO’s included in Accrued liabilities total
$2.7 million and $7.2 million at December 31, 2009 and 2008,
respectively. During 2009, the Company recorded accretion of $1.4
million and decreases in estimates, net of cash payments of $0.4
million. During 2008, the Company recorded accretion of $0.9 million
and increases in estimates, net of cash payments of $5.1 million.
Fair Value
Measurements
Certain
financial assets and liabilities as well as certain nonfinancial assets and
liabilities, such as the initial measurement of an asset retirement obligation
or the use of fair value in goodwill, intangible assets and long-lived assets
impairment tests, are valued and/or disclosed at fair value. The
Company describes its fair value measurements using a hierarchy of inputs based
primarily on the level of public data used. Level 1 inputs include quoted
market prices in active markets for identical assets or liabilities; Level 2
inputs include inputs other than Level 1 inputs that are directly or indirectly
observable; and Level 3 inputs include unobservable inputs using estimates and
assumptions developed using internal models, which reflect what a market
participant would use to determine fair value.
Earnings Per
Share
Earnings
per share are not presented as Utility Holdings’ common stock is wholly owned by
Vectren.
Other Significant
Policies
Included
elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 5).
|
3.
|
Utility
& Nonutility 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)
|
2009
|
2008
|
||||||||||||||
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
Original
Cost
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|||||||||||||
|
Gas
utility plant
|
$ | 2,299.1 | 3.5 | % | $ | 2,157.6 | 3.5 | % | ||||||||
|
Electric
utility plant
|
2,113.3 | 3.4 | % | 1,884.3 | 3.3 | % | ||||||||||
|
Common
utility plant
|
48.7 | 2.9 | % | 47.9 | 2.9 | % | ||||||||||
|
Construction
work in progress
|
140.3 | - | 245.5 | - | ||||||||||||
|
Total
original cost
|
$ | 4,601.4 | $ | 4,335.3 | ||||||||||||
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2009, is $178.1 million with accumulated depreciation totaling $53.4 million. The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $0.7 million at December 31, 2009. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.
Nonutility plant, net of
accumulated depreciation and amortization follows:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Computer
hardware & software
|
$ | 117.9 | $ | 127.5 | ||||
|
Land
& buildings
|
39.3 | 40.5 | ||||||
|
All
other
|
14.6 | 14.4 | ||||||
|
Nonutility
plant - net
|
$ | 171.8 | $ | 182.4 | ||||
Nonutility
plant is presented net of accumulated depreciation and amortization totaling
$160.2 million and $133.5 million as of December 31, 2009 and 2008,
respectively. For the years ended December 31, 2009, 2008, and 2007,
the Company capitalized interest totaling $0.2 million, $2.0 million, and $1.3
million, respectively, on nonutility plant construction projects.
|
4.
|
Regulatory
Assets & Liabilities
|
Regulatory
Assets
Regulatory assets consist of
the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Future
amounts recoverable from ratepayers related to:
|
||||||||
|
Deferred
income taxes
|
$ | 14.7 | $ | 11.4 | ||||
|
Asset
retirement obligations & other
|
4.3 | 8.5 | ||||||
| 19.0 | 19.9 | |||||||
|
Amounts
deferred for future recovery related to:
|
||||||||
|
Cost
recovery riders & other
|
1.0 | 1.7 | ||||||
| 1.0 | 1.7 | |||||||
|
Amounts
currently recovered in customer rates related to:
|
||||||||
|
Demand
side management programs
|
15.3 | 21.5 | ||||||
|
Unamortized
debt issue costs & hedging proceeds
|
38.1 | 38.4 | ||||||
|
Indiana
authorized trackers
|
15.6 | 13.8 | ||||||
|
Ohio
authorized trackers
|
8.2 | 11.6 | ||||||
|
Premiums
paid to reacquire debt & other
|
6.9 | 8.8 | ||||||
| 84.1 | 94.1 | |||||||
|
Total
regulatory assets
|
$ | 104.1 | $ | 115.7 | ||||
Of the
$84.1 million currently being recovered in customer rates, $15.3 million is
earning a return. The weighted average recovery period of regulatory
assets currently being recovered is 11 years. The Company has rate
orders for all deferred costs not yet in rates and therefore believes that
future recovery is probable.
Regulatory
Liabilities
At
December 31, 2009 and 2008, the Company has approximately $322.1 million and
$315.1 million, respectively, in Regulatory
liabilities. Of these amounts, $294.4 million and $292.4
million relate to cost of removal obligations. The remaining amounts
primarily relate to timing differences associated with asset retirement
obligations and deferred financing costs.
|
5.
|
Transactions
with Other Vectren Companies
|
Vectren Fuels,
Inc.
Vectren
Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines
from which SIGECO purchases coal used for electric generation. The
price of coal that is charged by Vectren Fuels to SIGECO is priced consistent
with contracts reviewed by the OUCC and on file with IURC. Amounts
paid for such purchases for the years ended December 31, 2009, 2008 and 2007,
totaled $152.9 million, $119.8 million, and $115.9 million,
respectively. Amounts owed to Vectren Fuels at December 31, 2009 and
2008 are included in Payables
to other Vectren companies.
Miller Pipeline
Corporation
Miller
Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren,
performs natural gas and water distribution, transmission, and construction
repair and rehabilitation primarily in the Midwest and the repair and
rehabilitation of gas, water, and wastewater facilities nationwide.
Miller’s customers include Utility Holdings’ utilities. Fees paid by
Utility Holdings and its subsidiaries totaled $40.4 million in 2009, $39.9
million in 2008, and $46.9 million in 2007. Amounts owed to Miller at
December 31, 2009 and 2008 are included in Payables to other Vectren
companies.
Vectren
Source
Vectren
Source, a nonutility wholly owned subsidiary of Vectren, provides natural gas
and other related products and services in the Midwest and Northeast United
States to over 189,000 equivalent residential and commercial
customers. This customer base reflects approximately 62,000 of VEDO’s
customers that have voluntarily opted to choose their natural gas supplier and
the supply of natural gas to nearly 33,000 equivalent customers in VEDO’s
service territory as part of VEDO’s process of exiting the merchant function,
which began October 1, 2008. As part of VEDO’s exiting process on
October 1, 2008, it transferred its natural gas inventory at book value to its
new suppliers, and now purchases natural gas from those suppliers, which include
Vectren Source, essentially on demand.
The cost
of natural gas inventory purchased by Vectren Source on October 1, 2008 totaled
approximately $31.6 million. The Company purchased natural gas from
Vectren Source totaling approximately $27.0 million in 2009 and $14.5 million in
2008, which represented approximately 4 percent and 2 percent of the Company’s
total gas purchased during 2009 and 2008, respectively. Amounts
charged by Vectren Source for gas supply services is comprised of the monthly
NYMEX settlement price plus a fixed adder, as authorized by the
PUCO. Amounts owed to Vectren Source at December 31, 2009 are
included in Payables to other
Vectren companies.
Support Services &
Purchases
Vectren
provides corporate and general and administrative services to the Company and
allocates costs to the Company, including costs for share-based compensation and
for pension and other postretirement benefits that are not directly charged to
subsidiaries. These costs have been allocated using various
allocators, including number of employees, number of customers and/or the level
of payroll, revenue contribution and capital
expenditures. Allocations are at cost. Utility Holdings
received corporate allocations totaling $48.4 million, $45.8 million, and $47.1
million for the years ended December 31, 2009, 2008 and 2007,
respectively.
Retirement Plans & Other
Postretirement Benefits
Vectren
has multiple defined benefit pension plans and postretirement plans that require
accounting in accordance with FASB guidance related to employers’ accounting for
defined benefit pension and other postretirement plans. An allocation
of cost is determined, comprised of only service cost and interest on that
service cost, by subsidiary based on headcount at each measurement
date. These costs are directly charged to individual
subsidiaries. Other components of costs (such as interest cost and
asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Neither plan assets nor the
ending liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. Further,
Vectren satisfies the future funding requirements of plans and the payment of
benefits from general corporate assets. This allocation methodology
is consistent with FASB guidance related to “multiemployer” benefit
accounting.
For the
years ended December 31, 2009, 2008 and 2007, periodic pension costs totaling
$5.4 million, $3.2 million and $5.2 million, respectively, were directly charged
by Vectren to the Company. For the years ended December 31, 2009,
2008 and 2007, other periodic postretirement benefit costs totaling $0.5
million, $0.3 million and $0.5 million, respectively, were directly charged by
Vectren to the Company. As of December 31, 2009 and 2008, $10.9
million and $38.5 million, respectively, is included in Deferred credits & other
liabilities and represents costs directly charged to the Company that is
yet to be funded to Vectren.
Cash Management
Arrangements
The
Company participates in Vectren’s centralized cash management
program.
Share-Based Incentive Plans
& Deferred Compensation Plans
Utility
Holdings does not have share-based compensation plans separate from
Vectren. The Company recognizes its allocated portion of expenses
related to share-based incentive plans and deferred compensation plans in
accordance with FASB guidance and to the extent these awards are expected to be
settled in cash that liability is pushed down to Utility Holdings. As
of December 31, 2009 and 2008, $28.5 million and $26.6 million, respectively, is
included in Deferred credits
& other liabilities and represents obligations that are yet to be
funded to Vectren.
Income
Taxes
Vectren
files a consolidated federal income tax return. Pursuant to a
subsidiary tax sharing agreement and for financial reporting purposes, Utility
Holdings’ current and deferred tax expense is computed on a separate company
basis. Current taxes payable/receivable are settled with Vectren in
cash.
Deferred
income taxes are provided for temporary differences between the tax basis
(adjusted for related unrecognized tax benefits, if any) of an asset or
liability and its reported amount in the financial statements. Deferred
tax assets and liabilities are computed based on the currently-enacted statutory
income tax rates that are expected to be applicable when the temporary
differences are scheduled to reverse. The Company’s rate-regulated
utilities recognize regulatory liabilities for deferred taxes provided in excess
of the current statutory tax rate and regulatory assets for deferred taxes
provided at rates less than the current statutory tax rate. Such
tax-related regulatory assets and liabilities are reported at the revenue
requirement level and amortized to income as the related temporary differences
reverse, generally over the lives of the related properties. A valuation
allowance is recorded to reduce the carrying amounts of deferred tax assets
unless it is more likely than not that the deferred tax assets will be
realized.
Tax
benefits associated with income tax positions taken, or expected to be taken, in
a tax return are recorded only when the more-likely-than-not recognition
threshold is satisfied and measured at the largest amount of benefit that is
greater than 50 percent likely of being realized upon settlement. The
Company reports interest and penalties associated with unrecognized tax benefits
within Income taxes in
the Consolidated Statements of
Income and reports tax liabilities related to unrecognized tax benefits
as part of Deferred credits
& other
liabilities.
Investment
tax credits (ITCs) are deferred and amortized to income over the approximate
lives of the related property in accordance with the regulatory
treatment. Production tax credits (PTCs) are recognized as energy is
generated and sold based on a per kilowatt hour rate prescribed in applicable
federal and state statutes.
Significant
components of the net deferred tax liability follow:
|
At
December 31,
|
|||||||||||
|
(In
millions)
|
2009 | 2008 | |||||||||
|
Noncurrent
deferred tax liabilities (assets):
|
|||||||||||
|
Depreciation
& cost recovery timing differences
|
$ | 431.8 | $ | 330.9 | |||||||
|
Regulatory
assets recoverable through future rates
|
25.6 | 27.8 | |||||||||
|
Other
comprehensive income
|
- | 0.1 | |||||||||
|
Alternative
minimum tax carryforward
|
(21.5 | ) | - | ||||||||
|
Employee
benefit obligations
|
(7.8 | ) | (22.1 | ) | |||||||
|
Regulatory
liabilities to be settled through future rates
|
(11.7 | ) | (15.7 | ) | |||||||
|
Other
– net
|
1.6 | 11.1 | |||||||||
|
Net
noncurrent deferred tax liability
|
418.0 | 332.1 | |||||||||
|
Current
deferred tax liabilities (assets):
|
|||||||||||
|
Deferred
fuel costs - net
|
1.2 | 2.6 | |||||||||
|
Alternative
minimum tax carryforward
|
(15.8 | ) | (11.2 | ) | |||||||
|
Demand
side management programs
|
5.2 | 8.8 | |||||||||
|
Other
– net
|
(7.7 | ) | (3.3 | ) | |||||||
|
Net
current deferred tax liability
|
(17.1 | ) | 340.1 | ||||||||
|
Net
deferred tax liability
|
$ | 400.9 | $ | 329.0 | |||||||
At December 31, 2009 and 2008, investment tax credits totaling $5.8 million and $6.9 million, respectively, are included in Deferred credits & other liabilities. At December 31, 2009, the Company has alternative minimum tax carryforwards of $37.3 million, which do not expire.
A
reconciliation of the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||
|
2009
|
2008
|
2007
|
||||||||
|
Statutory
rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
||||
|
State
and local taxes-net of federal benefit
|
2.9
|
3.4
|
3.9
|
|||||||
|
Amortization
of investment tax credit
|
(0.6)
|
(0.7)
|
(1.0)
|
|||||||
|
Tax
law changes and other adjustments to income tax accruals
|
(1.7)
|
(1.3)
|
0.2
|
|||||||
|
All
other - net
|
-
|
1.4
|
0.4
|
|||||||
|
Effective
tax rate
|
35.6
|
%
|
37.8
|
%
|
38.5
|
%
|
||||
The components of income tax expense and utilization of investment tax credits follow:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | (18.2 | ) | $ | 3.7 | $ | 43.7 | |||||
|
State
|
1.2 | 9.2 | 8.6 | |||||||||
|
Total
current taxes
|
(17.0 | ) | 12.9 | 52.3 | ||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
70.3 | 52.7 | 11.9 | |||||||||
|
State
|
7.0 | 3.3 | 4.2 | |||||||||
|
Total
deferred taxes
|
77.3 | 56.0 | 16.1 | |||||||||
|
Amortization
of investment tax credits
|
(1.1 | ) | (1.3 | ) | (1.7 | ) | ||||||
|
Total
income tax expense
|
$ | 59.2 | $ | 67.6 | $ | 66.7 | ||||||
Uncertain Tax Positions
Following
is a roll forward of the total amount of unrecognized tax benefits for the three
years ended December 31, 2009 and 2008:
|
(in
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Unrecognized
tax benefits at January 1
|
$ | 0.5 | $ | 3.8 | $ | 7.0 | ||||||
|
Gross
increases - tax positions in prior periods
|
1.0 | 0.3 | 0.3 | |||||||||
|
Gross
decreases - tax positions in prior periods
|
(1.9 | ) | (3.6 | ) | (3.5 | ) | ||||||
|
Gross
increases - current period tax positions
|
9.0 | - | - | |||||||||
|
Settlements
|
0.3 | - | - | |||||||||
|
Lapse
of statute of limitations
|
0.6 | - | - | |||||||||
|
Unrecognized
tax benefits at December 31
|
$ | 9.5 | $ | 0.5 | $ | 3.8 | ||||||
Of the change in unrecognized tax benefits during 2009 and 2008 almost none impacted the effective rate of the change in unrecognized tax benefits during 2007, $0.3 million impacted the effective tax rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.2 million at December 31, 2009 and almost none at December 31, 2008 and 2007.
As of
December 31, 2009, the unrecognized tax benefit relates to tax positions for
which the ultimate deductibility is highly certain but for which there is
uncertainty about the timing of such deductibility. Because of the impact
of deferred tax accounting, other than interest and penalties, the disallowance
of the shorter deductibility period would not affect the annual effective tax
rate but would accelerate the payment of cash to the taxing
authority.
The
Company recognized expense related to interest and penalties totaling
approximately $0.1 million in 2009, less than $0.1 million in 2008, and $0.5
million in 2007. The Company had approximately $0.2 million for the
payment of interest and penalties accrued as of December 31, 2009 and
2008.
The net
liability on the Consolidated
Balance Sheet for unrecognized tax benefits inclusive of interest,
penalties and net of secondary impacts which are a component of the Deferred income taxes,
totaled $8.9 million and $0.7 million, respectively, at December 31, 2009 and
2008.
From time
to time, the Company may consider changes to filed positions that could impact
its unrecognized tax benefits. However, it is not expected that such
changes would have a significant impact on earnings and would only affect the
timing of payments to taxing authorities.
As the
result of adopting changes to the accounting guidance for uncertain tax
positions on January 1, 2007, the Company recognized an approximate $0.3 million
increase in the liability for unrecognized tax benefits, of which $0.1 million
was accounted for as a reduction to the January 1, 2007 balance of Retained earnings and $0.2
million was recorded as an increase to Goodwill.
Utility
Holdings does not file federal or state income tax returns separate from those
filed by its parent, Vectren Corporation. Vectren files a
consolidated U.S. federal income tax return, and Vectren and/or certain of its
subsidiaries file returns in various states. The Internal Revenue Service
(IRS) has conducted examinations of Vectren’s U.S. federal income tax returns
for tax years through December 31, 2005. Subsequent to the year ended
December 31, 2009, Vectren received a notice from the IRS that year ended
December 31, 2008 is under audit. The State of Indiana, Vectren’s
primary state tax jurisdiction, has conducted examinations of state income tax
returns for tax years through December 31, 2007. The statutes of
limitations for assessment of federal and Indiana income tax have expired with
respect to tax years through 2002.
|
6.
|
Transactions
with Affiliated Vectren Companies
|
ProLiance Holdings, LLC
(ProLiance)
ProLiance
Holdings, LLC (ProLiance), a nonutility energy marketing
affiliate of Vectren and Citizens Energy Group (Citizens), provides services to
a broad range of municipalities, utilities, industrial operations, schools, and
healthcare institutions located throughout the Midwest and Southeast United
States. ProLiance’s customers include Vectren’s Indiana utilities and
nonutility gas supply operations as well as Citizens’
utilities. ProLiance’s primary businesses include gas marketing, gas
portfolio optimization, and other portfolio and energy management services.
Vectren received regulatory approval on April 25, 2006, from the IURC for
ProLiance to provide natural gas supply services to the Company’s Indiana
utilities through March 2011.
Transactions
with ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2009, 2008 and 2007 totaled $436.2 million, $739.3 million, and
$602.2 million, respectively. Amounts owed to ProLiance at December
31, 2009 and 2008, for those purchases were $54.1 million and $72.8 million,
respectively, and are included in Accounts payable to affiliated
companies in the Consolidated Balance Sheets. The Company
purchased approximately 76 percent of its gas through ProLiance in 2009 and 71
percent in 2008 and 2007. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.
|
7.
|
Borrowing
Arrangements
|
Long-Term
Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Utility
Holdings
|
||||||||
|
Fixed
Rate Senior Unsecured Notes
|
||||||||
| 2011, 6.625% | $ | 250.0 | $ | 250.0 | ||||
| 2013, 5.25% | 100.0 | 100.0 | ||||||
| 2015, 5.45% | 75.0 | 75.0 | ||||||
| 2018, 5.75% | 100.0 | 100.0 | ||||||
| 2020, 6.28% | 100.0 | - | ||||||
| 2035, 6.10% | 75.0 | 75.0 | ||||||
| 2036, 5.95% | 97.8 | 99.1 | ||||||
| 2039, 6.25% | 122.5 | 124.3 | ||||||
|
Total
Utility Holdings
|
920.3 | 823.4 | ||||||
|
SIGECO
|
||||||||
|
First
Mortgage Bonds
|
||||||||
|
2015, 1985 Pollution Control Series A, current adjustable rate
0.9%,
|
||||||||
|
tax exempt, 2008 weighted average: 0.37%
|
9.8 | 9.8 | ||||||
|
2016, 1986 Series, 8.875%
|
13.0 | 13.0 | ||||||
|
2020, 1998 Pollution Control Series B, 4.50%, tax exempt
|
4.6 | 4.6 | ||||||
|
2023, 1993 Environmental Improvement Series B, 5.15%, tax
exempt
|
22.6 | 22.6 | ||||||
|
2024, 2000 Environmental Improvement Series A, 4.65%, tax
exempt
|
22.5 | 22.5 | ||||||
|
2025, 1998 Pollution Control Series A, current adjustable rate
1.2%,
|
||||||||
|
tax exempt, 2008 weighted average: 0.44%
|
31.5 | 31.5 | ||||||
|
2029, 1999 Senior Notes, 6.72%
|
80.0 | 80.0 | ||||||
|
2030, 1998 Pollution Control Series B, 5.00%, tax exempt
|
22.0 | 22.0 | ||||||
|
2030, 1998 Pollution Control Series C, 5.35%, tax exempt
|
22.2 | 22.2 | ||||||
|
2040, 2009 Environmental Improvement Series, 5.40%, tax
exempt
|
22.3 | - | ||||||
|
2041, 2007 Pollution Control Series, 5.45%, tax exempt
|
17.0 | 17.0 | ||||||
|
Total SIGECO
|
267.5 | 245.2 | ||||||
|
Indiana
Gas
|
||||||||
|
Senior
Unsecured Notes
|
||||||||
|
2013, Series E, 6.69%
|
5.0 | 5.0 | ||||||
|
2015, Series E, 7.15%
|
5.0 | 5.0 | ||||||
|
2015, Series E, 6.69%
|
5.0 | 5.0 | ||||||
|
2015, Series E, 6.69%
|
10.0 | 10.0 | ||||||
|
2025, Series E, 6.53%
|
10.0 | 10.0 | ||||||
|
2027, Series E, 6.42%
|
5.0 | 5.0 | ||||||
|
2027, Series E, 6.68%
|
1.0 | 1.0 | ||||||
|
2027, Series F, 6.34%
|
20.0 | 20.0 | ||||||
|
2028, Series F, 6.36%
|
10.0 | 10.0 | ||||||
|
2028, Series F, 6.55%
|
20.0 | 20.0 | ||||||
|
2029, Series G, 7.08%
|
30.0 | 30.0 | ||||||
|
Total Indiana Gas
|
121.0 | 121.0 | ||||||
|
Total
long-term debt outstanding
|
1,308.8 | 1,189.6 | ||||||
|
Current
maturities of long-term debt
|
- | - | ||||||
|
Debt
subject to tender
|
(51.3 | ) | (80.0 | ) | ||||
|
Unamortized
debt premium & discount - net
|
(2.7 | ) | (3.2 | ) | ||||
|
Treasury
debt
|
- | (41.3 | ) | |||||
|
Total long-term debt-net
|
$ | 1,254.8 | $ | 1,065.1 | ||||
Utility
Holdings 2009 Debt Issuance
On April
7, 2009, Utility Holdings entered into a private placement Note Purchase
Agreement pursuant to which institutional investors purchased from Utility
Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020
(2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’
three utilities: SIGECO, Indiana Gas, and VEDO. These
guarantees are full and unconditional and joint and several. The
proceeds from the sale of the 2020 Notes, net of issuance costs, totaled
approximately $99.5 million.
The 2020
Notes have no sinking fund requirements, and interest payments are due
semi-annually. The 2020 Notes contain customary representations,
warranties and covenants, including a leverage covenant consistent with leverage
covenants contained in the Utility Holdings’ $515 million short-term credit
facility.
Utility
Holdings 2008 Debt Issuance
In March
2008, Utility Holdings issued at par $125 million in 6.25 percent senior
unsecured notes due April 1, 2039 (2039 Notes). The 2039 Notes are
guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas,
and VEDO. These guarantees are full and unconditional and joint and
several.
The 2039
Notes have no sinking fund requirements, and interest payments are due
monthly. The notes may be called by Utility Holdings, in whole or in
part, at any time on or after April 1, 2013, at 100 percent of principal amount
plus accrued interest. During 2007, Utility Holdings entered into
several interest rate hedges with an $80 million notional
amount. Upon issuance of the notes, these instruments were settled
resulting in the payment of approximately $9.6 million, which was recorded as a
Regulatory asset
pursuant to existing regulatory orders. The value paid is being
amortized as an increase to interest expense over the life of the
issue. The proceeds from the sale of the 2039 Notes less settlement
of the hedging arrangements and payments of issuance costs amounted to
approximately $111.1 million.
SIGECO
2009 Debt Issuance
On August
19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond
issuance at an interest rate of 5.4 percent that is fixed through
maturity. The bonds mature in 2040. The proceeds from the
sale of the bonds, net of issuance costs, totaled approximately $21.3
million.
Long-Term
Debt Put and Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised on
various dates before maturity. Other than certain instruments that
can be put to the Company upon the death of the holder (death puts), these put
or call provisions are not triggered by specific events, but are based upon
dates stated in the note agreements. During 2009 and 2008, the
Company repaid approximately $3.0 million and $1.6 million, respectively,
related to death puts. In 2007, no debt was put to the
Company. Debt which may be put to the Company for reasons other than
a death during the years following 2009 (in millions) is $10.0 in 2010, $30.0 in
2011, zero in 2012 and thereafter. Debt that may be put to the
Company within one year or debt that is supported by lines of credit that expire
within one year are classified as Long-term debt subject to
tender in current liabilities.
Auction
Rate Securities
On
December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt
long-term debt. The debt had a life of 33 years, maturing on January
1, 2041. The initial interest rate was set at 4.50 percent but the
rate was to reset every 7 days through an auction process that began December
13, 2007. This new debt was collateralized through the issuance of
first mortgage bonds and the payment of interest and principal was insured
through Ambac Assurance Corporation (Ambac).
In
February 2008, SIGECO provided notice to the current holders of approximately
$103 million of tax-exempt auction rate mode long-term debt, including the $17
million issued in December 2007, of its plans to convert that debt from its
current auction rate mode into a daily interest rate mode. In March
2008, the debt was tendered at 100 percent of the principal amount plus accrued
interest. During March 2008, SIGECO remarketed approximately $61.8
million of these instruments at interest rates that are fixed to maturity,
receiving proceeds, net of issuance costs, of approximately $60.0
million. The terms are $22.6 million at 5.15 percent due in 2023,
$22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due
in 2041.
On March
26, 2009, SIGECO remarketed the remaining $41.3 million of long-term debt held
in treasury at December 31, 2008, receiving proceeds, net of issuance costs of
approximately $40.6 million. The remarketed notes have a variable
rate interest rate which is reset weekly and are supported by a standby letter
of credit backed by Utility Holdings’ $515 million short-term credit
facility. The notes are collateralized by SIGECO’s utility plant, and
$9.8 million are due in 2015 and $31.5 million are due in 2025. The
initial interest rate paid to investors was 0.55 percent. The
equivalent rate of the debt at inception, inclusive of interest, weekly
remarketing fees, and letter of credit fees, approximated 1
percent. Because these notes are supported by Utility Holdings’ short
term credit facility and that facility expires within one year, such debt is
classified as Long-term debt
subject to tender in current liabilities.
Other
Financing Transactions
Other
Company debt totaling $6.5 million in 2007 was retired as
scheduled.
Future
Long-Term Debt Sinking Fund Requirements and Maturities
The
annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of
the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the
Trustee of unfunded property additions in the prescribed amount as provided in
the Mortgage Indenture. SIGECO intends to meet the 2010 sinking fund
requirement by this means and, accordingly, the sinking fund requirement for
2010 is excluded from Current
liabilities in the Consolidated Balance
Sheets. At December 31, 2009, $1.2 billion of SIGECO's utility
plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s
gross utility plant balance subject to the Mortgage Indenture approximated $2.5
billion at December 31, 2009.
Consolidated
maturities of long-term debt during the five years following 2009 (in millions)
are zero in 2010, $250.0 in 2011, zero in 2012, $105.0 in 2013, and zero in
2014.
Short-Term
Borrowings
At
December 31, 2009, the Company had $520 million of short-term borrowing
capacity, of which approximately $462 million was available. Interest
rates and outstanding balances associated with short-term borrowing arrangements
follows.
|
Year
Ended December 31,
|
|||||||||||||||
|
(In
millions)
|
2009 | 2008 | 2007 | ||||||||||||
|
Weighted
average commercial paper and bank loans
|
|||||||||||||||
|
outstanding
during the year
|
$ | 28.7 | $ | 178.2 | $ | 253.6 | |||||||||
|
Weighted
average interest rates during the year
|
|||||||||||||||
|
Commercial
paper
|
1.29 | % | 3.76 | % | 5.54 | % | |||||||||
|
Bank
loans
|
1.26 | % | 3.42 | % | N/A | ||||||||||
| At December 31, | |||||||||||||||
|
(In
millions)
|
2009 | 2008 | |||||||||||||
|
Commercial
paper
|
$ | 16.4 | $ | 91.5 | |||||||||||
|
Bank
loans
|
- | 100.4 | |||||||||||||
|
Total
short-term borrowings
|
$ | 16.4 | $ | 191.9 | |||||||||||
Covenants
Both
long-term and short-term borrowing arrangements contain customary default
provisions; restrictions on liens, sale-leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As an example, the Utility
Holdings’ short-term debt agreement expiring in 2010 contains a covenant that
the ratio of consolidated total debt to consolidated total capitalization will
not exceed 65 percent. As of December 31, 2009, the Company was in
compliance with all financial covenants.
|
8.
|
Common
Shareholder’s Equity
|
On June
27, 2008, Vectren physically settled an equity forward agreement associated with
a 2007 public offering of its common stock. Vectren transferred net
proceeds of approximately $124.8 million to Utility Holdings. The
proceeds received were recorded as an increase to Common Stock in Common
Shareholder’s Equity and are presented in the Statement of Cash Flows as a
financing activity.
In
addition to the $124.8 million capital contribution above, during the years
ended December 31, 2009, 2008, and 2007, the Company has cumulatively received
additional capital of $12.2 million from Vectren which was funded by new share
issues from Vectren’s dividend reinvestment plan.
|
9.
|
Accumulated
Other Comprehensive Income
|
Comprehensive
income is a measure of all changes in equity that result from the
non-shareholder transactions. This information is reported in the
Consolidated Statements of Common Shareholder’s Equity. A summary of
the components of and changes in Accumulated other comprehensive
income for the past three years follows:
|
2007
|
2008
|
2009
|
||||||||||||||||||||||||||
|
Beginning
|
Changes
|
End
|
Changes
|
End
|
Changes
|
End
|
||||||||||||||||||||||
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
During
|
of
Year
|
||||||||||||||||||||||
|
(In
millions)
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
|||||||||||||||||||||
|
Cash
flow hedges
|
$ | 1.4 | $ | (0.9 | ) | $ | 0.5 | $ | (0.4 | ) | $ | 0.1 | $ | - | $ | 0.1 | ||||||||||||
|
Deferred
income taxes
|
(0.5 | ) | 0.3 | (0.2 | ) | 0.2 | - | - | - | |||||||||||||||||||
|
Accumulated
other comprehensive income
|
$ | 0.9 | $ | (0.6 | ) | $ | 0.3 | $ | (0.2 | ) | $ | 0.1 | $ | - | $ | 0.1 | ||||||||||||
|
10.
|
Commitments
& Contingencies
|
Commitments
Future
minimum lease payments required under operating leases that have initial or
remaining noncancelable lease terms in excess of one year during the five years
following 2009 and thereafter (in millions) are $0.5 in 2010, $0.4 in 2011, $0.3
in 2012, $0.3 in 2013, $0.2 in 2014, and zero thereafter. Total lease
expense (in millions) was $0.9 in 2009, $1.6 in 2008, and $1.3 in
2007. Firm purchase commitments for commodities and utility plant
total zero in 2010 and 2011, $5.3 million in 2012, $5.5 million in 2013, $5.7
million in 2014, and zero thereafter.
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase natural gas, coal, and electricity as well as certain transportation
and storage rights. Costs arising from these commitments, while
significant, are pass-through costs, generally collected dollar-for-dollar from
retail customers through regulator-approved cost recovery
mechanisms. Because of the pass through nature of these costs, they
have not been included in the listing of contractual obligations.
Legal
Proceedings
The
Company is party to various legal proceedings, audits, and reviews by taxing
authorities and other government agencies arising in the normal course of
business. In the opinion of management, there are no legal
proceedings or other regulatory reviews or audits pending against the Company
that are likely to have a material adverse effect on its financial position,
results of operations or cash flows.
|
11.
|
Environmental
Matters
|
Clean Air
Act
The Clean
Air Interstate Rule (CAIR) is an allowance cap and trade program requiring
further reductions from coal-burning power plants in NOx emissions beginning
January 1, 2009 and SO2 emissions
beginning January 1, 2010, with a second phase of reductions in 2015. On
July 11, 2008, the US Court of Appeals for the District of Columbia vacated the
federal CAIR regulations. Various parties filed motions for
reconsideration, and on December 23, 2008, the Court reinstated the CAIR
regulations and remanded the regulations back to the USEPA for promulgation of
revisions in accordance with the Court’s July 11, 2008 Order. Thus,
the original version of CAIR promulgated in March of 2005 remains effective
while USEPA revises it per the Court’s guidance. It is possible that
a revised CAIR will require further reductions in NOx and SO2 from
SIGECO’s generating units. SIGECO is in compliance with the current
CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009 and
is positioned to comply with SO2 reductions
effective January 1, 2010. Utilization of the Company’s inventory of
NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. In response to the court decision, USEPA has announced
that it intends to publish proposed Maximum Achievable Control Technology
standards for mercury in 2010. It is uncertain what emission limit
the USEPA is considering, and whether they will address hazardous pollutants in
addition to mercury. It is also possible that the vacatur of the CAMR
regulations will lead to increased support for the passage of a multi-pollutant
bill in Congress.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. Prior to being included in base rates, return
on investments made and recovery of related operating expenses were recovered
through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. The Company
has invested approximately $100 million in this project. The scrubber
was placed into service on January 1, 2009. Recovery through a rider
mechanism of associated operating expenses including depreciation expense
associated with the scrubber also began on January 1, 2009. With the
SO2
scrubber fully operational, SIGECO is positioned for compliance with the
additional SO2 reductions
required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s
coal fired generating fleet is 100 percent scrubbed for SO2 and 90
percent controlled for NOx. SIGECO's investments in scrubber, SCR and
fabric filter technology allows for compliance with existing regulations and
should position it to comply with future reasonable pollution control
legislation, if and when, reductions in mercury and further reductions in NOx
and SO2 are
promulgated by USEPA.
Climate
Change
The U.S.
House of Representatives has passed a comprehensive energy bill that includes a
carbon cap and trade program in which there is a progressive cap on greenhouse
gas emissions and an auctioning and subsequent trading of allowances among those
that emit greenhouse gases, a federal renewable portfolio standard, and utility
energy efficiency targets. Current proposed legislation also requires
local natural gas distribution companies to hold allowances for the benefit of
their customers. As of the date of this filing, the Senate has not
passed a bill, and the House bill is not law. The U.S. Senate is
currently debating a cap and trade proposal that is similar in structure to the
House bill.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in Indiana,
the state is an observer to the Midwestern Regional Greenhouse Gas Reduction
Accord, and in its completed 2009 session, the state’s legislature debated, but
did not pass, a renewable energy portfolio standard.
In
advance of a federal or state renewable portfolio standard, SIGECO received
regulatory approval to purchase a 3 MW landfill gas generation facility from a
related entity. The facility was purchased in 2009 and is directly
interconnected to the Company’s distribution system. In 2009, the
Company also executed a long term purchase power commitment for 50 MW of wind
energy. These transactions supplement a 30 MW wind energy purchase
power agreement executed in 2008.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. In April of 2009, the USEPA published its proposed
endangerment finding for public comment. The proposed endangerment
finding concludes that carbon emissions from mobile sources pose an endangerment
to public health and the environment. The endangerment finding was
finalized in December of 2009, and is the first step toward USEPA regulating
carbon emissions through the existing Clean Air Act in the absence of specific
carbon legislation from Congress. Therefore, any new regulations
would likely also impact major stationary sources of greenhouse
gases. The USEPA has recently finalized a mandatory greenhouse gas
emissions registry which will require reporting of emissions beginning in 2011
(for the emission year 2010). The USEPA has also recently proposed a
revision to the PSD (Prevention of Significant Deterioration) and Title V
permitting rules which would require facilities that emit 25,000 tons or more of
greenhouse gases a year to obtain a PSD permit for new construction or a
significant modification of an existing facility. If these proposed
rules were adopted, they would apply to SIGECO’s generating
facilities.
Impact
of Legislative Actions & Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants and
natural gas distribution businesses. Further, any legislation would likely
impact the Company’s generation resource planning decisions. At this time
and in the absence of final legislation, compliance costs and other effects
associated with reductions in greenhouse gas emissions or obtaining renewable
energy sources remain uncertain. The Company has gathered preliminary
estimates of the costs to comply with a cap and trade approach to controlling
greenhouse gas emissions. A preliminary investigation demonstrated
costs to comply would be significant, first with regard operating expenses for
the purchase of allowances, and later for capital expenditures as technology
becomes available to control greenhouse gas emissions. However, these
compliance cost estimates are based on highly uncertain assumptions, including
allowance prices and energy efficiency targets. Costs to purchase
allowances that cap greenhouse gas emissions should be considered a cost of
providing electricity, and as such, the Company believes recovery should be
timely reflected in rates charged to customers. Approximately 20
percent of electric volumes sold in 2008 were delivered to municipal and other
wholesale customers. As such, reductions in these volumes in 2009
coupled with the flexibility to further modify the level of these transactions
in future periods may help with compliance if emission targets are based on
pre-2008 levels.
Ash Ponds & Coal Ash
Disposal Regulations
The USEPA
is considering additional regulatory measures affecting the management and
disposal of coal combustion products, such as ash generated by the Company’s
coal-fired power plants. Additional laws and regulations under
consideration more stringently regulate these byproducts, including the
potential for coal ash to be considered a hazardous waste in certain
circumstances. The USEPA has indicated that it intends to propose a rule
during 2010. At this time, the Company is unable to predict the
outcome any such revised regulations might have on operating results, financial
position, or liquidity.
Jacobsville Superfund
Site
On July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The
USEPA has identified four sources of historic lead
contamination. These four sources shut down manufacturing operations
years ago. When drawing up the boundaries for the listing, the USEPA
included a 250 acre block of properties surrounding the Jacobsville
neighborhood, including Vectren's Wagner Operations Center. Vectren's
property has not been named as a source of the lead
contamination. Vectren's own soil testing, completed during the
construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils above industrial cleanup
levels. At this time, it is anticipated that the USEPA may request
only additional soil testing at some future date.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that owned or
operated these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded cumulative costs
that it reasonably expects to incur totaling approximately $23.2
million. The estimated accrued costs are limited to Indiana Gas’
share of the remediation efforts. Indiana Gas has arrangements in
place for 19 of the 26 sites with other potentially responsible parties (PRP),
which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50
percent.
With
respect to insurance coverage, Indiana Gas has settled with all known insurance
carriers under insurance policies in effect when these plants were in operation
in an aggregate amount approximating $20.8 million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another waste
disposal site subject to potential environmental remediation
efforts. With respect to that lawsuit, in an October 2009 court
decision, SIGECO was found to be a PRP at the site. However, the
Court must still determine whether such costs should be allocated among a number
of PRPs, including the former owners of the site. SIGECO has filed a
declaratory judgment action against its insurance carriers seeking a judgment
finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit.
SIGECO
has recorded cumulative costs that it reasonably expects to incur related to
these environmental matters totaling approximately $11.1
million. However, given the uncertainty surrounding the allocation of
PRP responsibility associated with the May 2007 lawsuit and other matters, the
total costs that may be incurred in connection with addressing all of these
sites cannot be determined at this time. With respect to insurance
coverage, SIGECO has settled with certain of its known insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.1 million; negotiations are ongoing with others. SIGECO
has undertaken significant remediation efforts at two MGP sites.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. While
the Company’s utilities have recorded all costs which they presently expect to
incur in connection with activities at these sites, it is possible that future
events may require some level of additional remedial activities which are not
presently foreseen and those costs may not be subject to PRP or insurance
recovery. As of December 31, 2009 and December 31, 2008,
approximately $6.5 million of accrued, but not yet spent, remediation costs are
included in Other Liabilities
related to both the Indiana Gas and SIGECO sites.
|
12.
|
Rate
& Regulatory Matters
|
Vectren South Electric Base
Rate Filings
On
December 11, 2009, the Company filed a request with the IURC to adjust its
electric base rates in its South service territory. The requested
increase in base rates addresses capital investments, a modified electric rate
design that facilitates a partnership between the Company and customers to
pursue energy efficiency and conservation, and new energy efficiency programs to
complement those currently offered for natural gas customers. In
total the request approximated $54 million. The request addresses the
roughly $325 million spent in infrastructure construction since its last base
rate increase in August 2007 that was needed to continue to provide reliable
service. Most of the remainder of the request is to account for the
now lower overall sales levels resulting from the recession. A
portion of the request reflects a slight increase in annual operating and
maintenance costs since the last rate case, nearly four years
ago. The rate design proposed in the filing would break the link
between customers’ consumption and the utility’s rate of return, thereby
aligning the utility’s and customers’ interests in using less
energy. The request assumes an overall rate of return of 7.62 percent
on rate base of approximately $1,294 million and an allowed return on equity
(ROE) of 10.7 percent. Based upon timelines prescribed by the IURC at
the start of these proceedings, a decision is expected to be issued at the end
of 2010.
VEDO Gas Base Rate Order
Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also adjusted the rate design used to collect the agreed-upon revenue from
VEDO's customers. The order allows for the phased movement toward a
straight fixed variable rate design which places substantially all of the fixed
cost recovery in the customer service charge. A straight fixed
variable design mitigates most weather risk as well as the effects of declining
usage, similar to the Company’s lost margin recovery mechanism, which expired
when this new rate design went into effect on February 22, 2009. In
2008, annual results include approximately $4.3 million of revenue from a lost
margin recovery mechanism that did not continue once this base rate increase
went into effect. After year one, nearly 90 percent of the combined
residential and commercial base rate margins were recovered through the customer
service charge. The OCC has filed a request for rehearing on the rate
design finding by the PUCO. The rehearing request mirrors similar
requests filed by the OCC in each case where the PUCO has approved similar rate
designs. The Ohio Supreme Court has yet to act on the OCC’s request
in this instance, but in two similar cases, the Court denied such
requests.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of uncollectible accounts
and percent of income payment plan (PIPP) expenses; base rate recovery of
pipeline integrity management expense; timely recovery of costs associated with
the accelerated replacement of bare steel and cast iron pipes, as well as
certain service risers; and expanded conservation programs now totaling up to $5
million in annual expenditures. The straight fixed variable rate
design will be fully phased in by February 2010.
VEDO Continues the Process
to Exit the Merchant Function
On August
20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers
to provide the gas commodity to the Company for resale to its customers at
auction-determined standard pricing. This standard pricing is
comprised of the monthly NYMEX settlement price plus a fixed
adder. This auction, which is effective from October 1, 2008 through
March 31, 2010, is the initial step in exiting the merchant function in the
Company’s Ohio service territory. The approach eliminated the need
for monthly gas cost recovery (GCR) filings and prospective PUCO GCR
audits. On October 1, 2008, VEDO’s entire natural gas inventory was
transferred, receiving proceeds of approximately $107 million.
The
second phase of the exit process begins on April 1, 2010, during which the
Company will no longer sell natural gas directly to these
customers. Rather, state-certified Competitive Retail Natural Gas
Suppliers, that are successful bidders in a second regulatory-approved auction,
will sell the gas commodity to specific customers for 12 months at
auction-determined standard pricing. That auction was conducted on
January 12, 2010, and the auction results were approved by the PUCO on January
13. The plan approved by the PUCO requires that the Company conduct at
least two auctions during this phase. As such, the Company will conduct
another auction in advance of the second 12-month term, which will commence on
April 1, 2011. Consistent with current practice, customers will
continue to receive one bill for the delivery of natural gas
service.
The PUCO
has also provided for an Exit Transition Cost rider, which allows the Company to
recover costs associated with the transition. As the cost of gas is
currently passed through to customers through a PUCO approved recovery
mechanism, the impact of exiting the merchant function should not have a
material impact on Company earnings or financial condition.
Vectren North (Indiana Gas
Company, Inc.) Gas Base Rate Order Received
On
February 13, 2008, the Company received an order from the IURC which approved
the settlement agreement reached in its Vectren North gas rate case. The
order provided for a base rate increase of $16.3 million and a return on equity
(ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate
base of approximately $793 million. The order also provides for the
recovery of $10.6 million of costs through separate cost recovery mechanisms
rather than base rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for AFUDC and the deferral
of depreciation expense after the projects go in service but before they are
included in base rates. To qualify for this treatment, the annual
expenditures are limited to $20 million and the treatment cannot extend beyond
four years on each project.
With this
order, the Company has in place for its North gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a uncollectible accounts expense level based on
historical experience and unaccounted for gas through the existing gas cost
adjustment mechanism, and tracking of pipeline integrity management
expense.
Vectren South Gas Base Rate
Order Received
On August
1, 2007, the Company received an order from the IURC which approved the
settlement reached in Vectren South’s gas rate case. The order provided
for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an
overall rate of return of 7.2 percent on rate base of approximately $122
million. The order also provided for the recovery of $2.6 million of
costs through separate cost recovery mechanisms rather than base
rates.
Further,
additional expenditures for a multi-year bare steel and cast iron capital
replacement program will be afforded certain accounting treatment that mitigates
earnings attrition from the investment between rate cases. The accounting
treatment allows for the continuation of the accrual for AFUDC and the deferral
of depreciation expense after the projects go in service but before they are
included in base rates. To qualify for this treatment, the annual
expenditures are limited to $3 million and the treatment cannot extend beyond
three years on each project.
With this
order, the Company now has in place for its South gas territory weather
normalization, a conservation and lost margin recovery tariff, tracking of gas
cost expense related to a uncollectible accounts expense level based on
historical experience and unaccounted for gas through the existing gas cost
adjustment mechanism, and tracking of pipeline integrity management
expense.
Vectren South (SIGECO)
Electric Base Rate Order Received
In August
2007, the Company received an order from the IURC which approved the settlement
reached in Vectren South’s electric rate case. The order provided for an
approximate $60.8 million electric rate increase to cover the Company’s cost of
system growth, maintenance, safety and reliability. The order provided
for, among other things: recovery of ongoing costs and deferred costs associated
with the MISO; operations and maintenance (O&M) expense increases related to
managing the aging workforce, including the development of expanded
apprenticeship programs and the creation of defined training programs to ensure
proper knowledge transfer, safety and system stability; increased O&M
expense necessary to maintain and improve system reliability; benefit to
customers from the sale of wholesale power by Vectren sharing equally with
customers any profit earned above or below $10.5 million of wholesale power
margin; recovery of and return on the investment in past demand side management
programs to help encourage conservation during peak load periods; timely
recovery of the Company’s investment in certain new electric transmission
projects that benefit the MISO infrastructure; an overall rate of return of 7.32
percent on rate base of approximately $1,044 million and an allowed ROE of 10.4
percent.
MISO
Since
2002 and with the IURC’s approval, the Company has been a member of the MISO, a
FERC approved regional transmission organization. The MISO serves the
electrical transmission needs of much of the Midwest and maintains operational
control over the Company’s electric transmission facilities as well as that of
other Midwest utilities. Since April 1, 2005, the Company has been an
active participant in the MISO energy markets, bidding its owned generation into
the Day Ahead and Real Time markets and procuring power for its retail customers
at Locational Marginal Pricing (LMP) as determined by the MISO
market.
MISO-related
purchase and sale transactions are recorded using settlement information
provided by MISO. These purchase and sale transactions are accounted for on a
net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power
and net sales in a single hour are recorded in Electric utility revenues. On
occasion, prior period transactions are resettled outside the routine process
due to a change in MISO’s tariff or a material interpretation
thereof. Expenses associated with resettlements are recorded once the
resettlement is probable and the resettlement amount can be estimated. Revenues
associated with resettlements are recognized when the amount is determinable and
collectability is reasonably assured.
Since the
Company became an active MISO member, its generation optimization strategies
primarily involve the sale of excess generation into the MISO day ahead and
real-time markets. The Company also has municipal customers served
through the MISO and for which the Company transmits power to the MISO for
delivery to those customers. Net revenues from wholesale activities,
inclusive of revenues associated with these municipal contracts, totaled $20.8
million in 2009, $57.6 million in 2008, and $35.0 million in 2007 and are
recorded in Electric utility
revenues. The base rate case effective August 17, 2007,
requires that wholesale margin (net revenues less the cost of fuel and purchased
power) inclusive of this MISO wholesale activity earned above or below $10.5
million be shared equally with retail customers as measured on a fiscal year
ending in August.
Recently,
MISO market prices have fallen and the Company has more frequently been a net
purchaser. In addition, the Company also receives power through the
MISO associated with its wind and other power purchase
agreements. Including these power purchase agreements, the Company
purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in
2008, and $18.2 million in 2007. To the extent these power purchases
are used for retail load, they are included in FAC filings.
The
Company also receives transmission revenue that results from other members’ use
of the Company’s transmission system. These revenues are also
included in Electric utility
revenues. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered from / refunded to retail
customers through tracking mechanisms.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to recover costs associated with ASM. To
date impacts from the ASM have been minor.
The need
to expend capital for improvements to the regional transmission system, both to
SIGECO’s facilities as well as to those facilities of adjacent utilities, over
the next several years is expected to be significant. Beginning in
June 2008, the Company began timely recovering its investment in certain new
electric transmission projects that benefit the MISO infrastructure at a FERC
approved rate of return. Such revenues recorded in Electric utility revenues
associated with projects meeting the criteria of MISO’s transmission
expansion plans totaled $9.1 million in 2009 and $4.8 million in
2008.
|
13.
|
Fair
Value Measurements
|
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
||||||||||||||||
|
2009
|
2008
|
|||||||||||||||
|
(In
millions)
|
Carrying
Amount
|
Est.
Fair
Value
|
Carrying
Amount
|
Est.
Fair
Value
|
||||||||||||
|
Long-term
debt
|
$ | 1,308.8 | $ | 1,366.4 | $ | 1,189.6 | $ | 1,068.3 | ||||||||
|
Short-term
borrowings
|
16.4 | 16.4 | 191.9 | 191.9 | ||||||||||||
|
Cash
& cash equivalents
|
6.2 | 6.2 | 52.5 | 52.5 | ||||||||||||
For the balance sheet dates presented in these financial statements, other than $40 million invested in money market funds and included in Cash and cash equivalents as of December 31, 2008, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs. The money market investments were valued using Level 1 inputs.
Certain
methods and assumptions must be used to estimate the fair value of financial
instruments. The fair value of the Company's long-term debt was
estimated based on the quoted market prices for the same or similar issues or on
the current rates offered to the Company for instruments with similar
characteristics. Because of the maturity dates and variable interest
rates of short-term borrowings and cash & cash equivalents, those carrying
amounts approximate fair value. Because of the inherent difficulty of
estimating interest rate and other market risks, the methods used to estimate
fair value may not always be indicative of actual realizable value, and
different methodologies could produce different fair value estimates at the
reporting date.
-64-
Under
current regulatory treatment, call premiums on reacquisition of long-term debt
are generally recovered in customer rates over the life of the refunding issue
or over a 15-year period. Accordingly, any reacquisition would not be
expected to have a material effect on the Company's results of
operations.
|
14.
|
Segment
Reporting
|
The
Company’s operations consist of regulated operations and other operations that
provide information technology and other support services to those regulated
operations. The Company segregates its regulated operations into a
Gas Utility Services operating segment and an Electric Utility Services
operating segment. The Gas Utility Services segment provides natural
gas distribution and transportation services to nearly two-thirds of Indiana and
to west central Ohio. The Electric Utility Services segment provides
electric distribution services primarily to southwestern Indiana, and includes
the Company’s power generating and wholesale power operations. The
Company manages its regulated operations as separated between Energy Delivery,
which includes the gas and electric transmission and distribution functions, and
Power Supply, which includes the power generating and wholesale power
operations. In total, regulated operations supply natural gas and /or
electricity to over one million customers. Net income is the measure
of profitability used by management for all operations.
Information
related to the Company’s business segments is summarized below:
|
Year
Ended December 31,
|
||||||||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
|||||||||
|
Revenues
|
||||||||||||
|
Gas
Utility Services
|
$ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
|
Electric
Utility Services
|
528.6 | 524.2 | 487.9 | |||||||||
|
Other
Operations
|
42.8 | 36.8 | 40.4 | |||||||||
|
Eliminations
|
(41.2 | ) | (35.0 | ) | (38.7 | ) | ||||||
|
Total
revenues
|
$ | 1,596.2 | $ | 1,958.7 | $ | 1,759.0 | ||||||
|
Profitability
Measure - Net Income
|
||||||||||||
|
Gas
Utility Services
|
$ | 50.2 | $ | 53.3 | $ | 41.7 | ||||||
|
Electric
Utility Services
|
48.3 | 50.7 | 52.6 | |||||||||
|
Other
Operations
|
8.9 | 7.1 | 12.2 | |||||||||
|
Total
net income
|
$ | 107.4 | $ | 111.1 | $ | 106.5 | ||||||
|
Amounts
Included in Profitability Measures
|
||||||||||||
|
Depreciation
& Amortization
|
||||||||||||
|
Gas
Utility Services
|
$ | 76.9 | $ | 74.1 | $ | 70.6 | ||||||
|
Electric
Utility Services
|
77.5 | 68.5 | 66.0 | |||||||||
|
Other
Operations
|
26.5 | 22.9 | 21.8 | |||||||||
|
Total
depreciation & amortization
|
$ | 180.9 | $ | 165.5 | $ | 158.4 | ||||||
|
Interest
Expense
|
||||||||||||
|
Gas
Utility Services
|
$ | 38.8 | $ | 42.0 | $ | 39.8 | ||||||
|
Electric
Utility Services
|
34.8 | 32.0 | 29.6 | |||||||||
|
Other
Operations
|
5.6 | 5.9 | 11.2 | |||||||||
|
Total
interest expense
|
$ | 79.2 | $ | 79.9 | $ | 80.6 | ||||||
|
Income
Taxes
|
||||||||||||
|
Gas
Utility Services
|
$ | 31.3 | $ | 35.5 | $ | 33.2 | ||||||
|
Electric
Utility Services
|
27.4 | 32.0 | 38.0 | |||||||||
|
Other
Operations
|
0.5 | 0.1 | (4.5 | ) | ||||||||
|
Total
income taxes
|
$ | 59.2 | $ | 67.6 | $ | 66.7 | ||||||
|
Capital
Expenditures
|
||||||||||||
|
Gas
Utility Services
|
$ | 121.1 | $ | 110.4 | $ | 128.9 | ||||||
|
Electric
Utility Services
|
154.1 | 172.0 | 134.7 | |||||||||
|
Other
Operations
|
16.7 | 29.6 | 36.4 | |||||||||
|
Non-cash
costs & changes in accruals
|
15.0 | (5.7 | ) | 2.5 | ||||||||
|
Total
capital expenditures
|
$ | 306.9 | $ | 306.3 | $ | 302.5 | ||||||
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Assets
|
||||||||
|
Utility
Group
|
||||||||
|
Gas
Utility Services
|
$ | 2,102.4 | $ | 2,204.7 | ||||
|
Electric
Utility Services
|
1,592.4 | 1,462.1 | ||||||
|
Other
Operations, net of eliminations
|
128.3 | 171.3 | ||||||
|
Total
assets
|
$ | 3,823.1 | $ | 3,838.1 | ||||
|
15.
|
Additional
Balance Sheet & Operational
Information
|
Prepayments & other current
assets in the Consolidated Balance Sheets consist of the
following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Prepaid
gas delivery service
|
$ | 38.7 | $ | 75.0 | ||||
|
Prepaid
taxes
|
11.4 | 19.3 | ||||||
|
Deferred
income taxes
|
17.1 | 3.1 | ||||||
|
Other
prepayments & current assets
|
2.0 | 5.7 | ||||||
|
Total
prepayments & other current assets
|
$ | 69.2 | $ | 103.1 | ||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Refunds
to customers & customer deposits
|
$ | 51.0 | $ | 45.5 | ||||
|
Accrued
taxes
|
36.9 | 45.2 | ||||||
|
Accrued
interest
|
19.6 | 18.0 | ||||||
|
Asset
retirement obligation
|
2.7 | 7.2 | ||||||
|
Accrued
salaries & other
|
21.2 | 31.8 | ||||||
|
Total
accrued liabilities
|
$ | 131.4 | $ | 147.7 | ||||
Other investments in the Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
||||||||
|
(In
millions)
|
2009
|
2008
|
||||||
|
Cash
surrender value of life insurance policies
|
$ | 23.1 | $ | 18.5 | ||||
|
Municipal
bond
|
4.3 | 4.5 | ||||||
|
Restricted
cash
|
2.8 | - | ||||||
|
Other
investments
|
1.2 | 1.2 | ||||||
|
Total
other investments
|
$ | 31.4 | $ | 24.1 | ||||
Other – net in the
Consolidated Statements of Income consists of the following:
|
Year
Ended December 31,
|
|||||||||||||||
|
(In
millions)
|
2009 | 2008 | 2007 | ||||||||||||
|
AFUDC
- borrowed funds
|
$ | 1.3 | $ | 2.2 | $ | 3.5 | |||||||||
|
AFUDC
- equity funds
|
0.7 | 0.3 | 0.5 | ||||||||||||
|
Nonutility
plant capitalized interest
|
0.2 | 2.0 | 1.3 | ||||||||||||
|
Interest
income
|
0.7 | 1.0 | 2.3 | ||||||||||||
|
Cash
surrender value of life insurance policies
|
3.9 | (2.6 | ) | 0.5 | |||||||||||
|
Other
income
|
1.0 | 1.1 | 1.3 | ||||||||||||
|
Total
other – net
|
$ | 7.8 | $ | 4.0 | $ | 9.4 | |||||||||
Supplemental
Cash Flow Information:
|
Year
Ended December 31,
|
|||||||
|
(In
millions)
|
2009
|
2008
|
2007
|
||||
|
Cash
paid for:
|
|||||||
|
Interest
|
77.6
|
74.9
|
77.1
|
||||
|
Income
taxes
|
(26.1)
|
14.8
|
44.9
|
||||
As of
December 31, 2009 and 2008, the Company has accruals related to utility and
nonutility plant purchases totaling approximately $8.8 million and $30.3
million, respectively.
|
16.
|
Impact
of Recently Issued Accounting
Guidance
|
Variable
Interest Entities
In June
2009, the FASB issued new accounting guidance regarding variable interest
entities (VIE’s). This new guidance is effective for annual reporting
periods beginning after November 15, 2009. This guidance requires a
qualitative analysis of which holder of a variable interest controls the VIE and
if that interest holder must consolidate a VIE. Additionally, it
requires additional disclosures and an ongoing reassessment of who must
consolidate a VIE. The Company adopted this guidance on January 1,
2010. The Company does not expect the adoption will have a material impact on
the consolidated financial statements.
In
January 2010, the FASB issued new accounting guidance on improving disclosures
about fair market value. This guidance amends prior disclosure
requirements involving fair value measurements to add new requirements for
disclosures about transfers into and out of Levels 1 and 2 and separate
disclosures about purchases, sales, issuances, and settlements relating to Level
3 measurements. The guidance also clarifies existing fair value disclosures in
regard to the level of disaggregation and about inputs and valuation techniques
used to measure fair value. The guidance also amends prior disclosure
requirements regarding postretirement benefit plan assets to require that
disclosures be provided by classes of assets instead of major categories of
assets. This guidance is effective for the first reporting period
beginning after December 15, 2009. The Company will adopt this
guidance in its first quarter 2010 reporting. The Company does not
expect the adoption will have a material impact on the consolidated financial
statements.
|
17.
|
Subsidiary
Guarantor & Consolidating
Information
|
The
Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of Utility Holdings’ $515 million in short-term credit facilities, of
which $16 million is outstanding at December 31, 2009, and Utility Holdings’
$920 million unsecured senior notes outstanding at December 31,
2009. The guarantees are full and unconditional and joint and
several, and Utility Holdings has no subsidiaries other than the subsidiary
guarantors. However, Utility Holdings does have operations other than
those of the subsidiary guarantors. Pursuant to Item 3-10 of
Regulation S-X, disclosure of the results of operations and balance sheets of
the subsidiary guarantors, which are 100 percent owned, separate from the
parent company’s operations is required. Following are consolidating
financial statements including information on the combined operations of the
subsidiary guarantors separate from the other operations of the parent
company. Pursuant to a tax sharing agreement, consolidating tax
effects, which are calculated on a separate return basis, are reflected at the
parent level.
Consolidating Statement of
Income for the year ended December 31, 2009 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,066.0 | $ | - | $ | - | $ | 1,066.0 | ||||||||
|
Electric
utility
|
528.6 | - | - | 528.6 | ||||||||||||
| Other | - | 42.8 | (41.2 | ) | 1.6 | |||||||||||
|
Total
operating revenues
|
1,594.6 | 42.8 | (41.2 | ) | 1,596.2 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
618.1 | - | - | 618.1 | ||||||||||||
|
Cost
of fuel & purchased power
|
194.3 | - | - | 194.3 | ||||||||||||
|
Other
operating
|
345.3 | 0.1 | (40.8 | ) | 304.6 | |||||||||||
|
Depreciation
& amortization
|
154.1 | 26.5 | 0.3 | 180.9 | ||||||||||||
|
Taxes
other than income taxes
|
58.6 | 1.6 | 0.1 | 60.3 | ||||||||||||
|
Total
operating expenses
|
1,370.4 | 28.2 | (40.4 | ) | 1,358.2 | |||||||||||
|
OPERATING
INCOME
|
224.2 | 14.6 | (0.8 | ) | 238.0 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 98.5 | (98.5 | ) | - | |||||||||||
|
Other
– net
|
6.6 | 50.9 | (49.7 | ) | 7.8 | |||||||||||
|
Total
other income (expense)
|
6.6 | 149.4 | (148.2 | ) | 7.8 | |||||||||||
|
Interest
expense
|
73.6 | 56.1 | (50.5 | ) | 79.2 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
157.2 | 107.9 | (98.5 | ) | 166.6 | |||||||||||
|
Income
taxes
|
58.7 | 0.5 | - | 59.2 | ||||||||||||
|
NET
INCOME
|
$ | 98.5 | $ | 107.4 | $ | (98.5 | ) | $ | 107.4 | |||||||
Consolidating Statement of Income for the year ended December 31, 2008 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,432.7 | $ | - | $ | - | $ | 1,432.7 | ||||||||
|
Electric
utility
|
524.2 | - | - | $ | 524.2 | |||||||||||
| Other | - | 36.8 | (35.0 | ) | $ | 1.8 | ||||||||||
|
Total
operating revenues
|
1,956.9 | 36.8 | (35.0 | ) | 1,958.7 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
983.1 | - | - | 983.1 | ||||||||||||
|
Cost
of fuel & purchased power
|
182.9 | - | - | 182.9 | ||||||||||||
|
Other
operating
|
334.2 | - | (33.9 | ) | 300.3 | |||||||||||
|
Depreciation
& amortization
|
142.3 | 22.9 | 0.3 | 165.5 | ||||||||||||
|
Taxes
other than income taxes
|
70.5 | 1.7 | 0.1 | 72.3 | ||||||||||||
|
Total
operating expenses
|
1,713.0 | 24.6 | (33.5 | ) | 1,704.1 | |||||||||||
|
OPERATING
INCOME
|
243.9 | 12.2 | (1.5 | ) | 254.6 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 104.0 | (104.0 | ) | - | |||||||||||
|
Other
– net
|
1.6 | 52.4 | (50.0 | ) | 4.0 | |||||||||||
|
Total
other income (expense)
|
1.6 | 156.4 | (154.0 | ) | 4.0 | |||||||||||
|
Interest
expense
|
74.0 | 57.4 | (51.5 | ) | 79.9 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
171.5 | 111.2 | (104.0 | ) | 178.7 | |||||||||||
|
Income
taxes
|
67.5 | 0.1 | - | 67.6 | ||||||||||||
|
NET
INCOME
|
$ | 104.0 | $ | 111.1 | $ | (104.0 | ) | $ | 111.1 | |||||||
Consolidating Statement of
Income for the year ended December 31, 2007 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Gas
utility
|
$ | 1,269.4 | $ | - | $ | - | $ | 1,269.4 | ||||||||
|
Electric
utility
|
487.9 | - | - | 487.9 | ||||||||||||
| Other | - | 40.4 | (38.7 | ) | 1.7 | |||||||||||
|
Total
operating revenues
|
1,757.3 | 40.4 | (38.7 | ) | 1,759.0 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Cost
of gas sold
|
847.2 | - | - | 847.2 | ||||||||||||
|
Cost
of fuel & purchased power
|
174.8 | - | - | 174.8 | ||||||||||||
|
Other
operating
|
301.5 | - | (35.4 | ) | 266.1 | |||||||||||
|
Depreciation
& amortization
|
136.6 | 21.5 | 0.3 | 158.4 | ||||||||||||
|
Taxes
other than income taxes
|
66.0 | 2.1 | - | 68.1 | ||||||||||||
|
Total
operating expenses
|
1,526.1 | 23.6 | (35.1 | ) | 1,514.6 | |||||||||||
|
OPERATING
INCOME
|
231.2 | 16.8 | (3.6 | ) | 244.4 | |||||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||||||
|
Equity
in earnings of consolidated companies
|
- | 94.3 | (94.3 | ) | - | |||||||||||
|
Other
– net
|
3.7 | 48.3 | (42.6 | ) | 9.4 | |||||||||||
|
Total
other income (expense)
|
3.7 | 142.6 | (136.9 | ) | 9.4 | |||||||||||
|
Interest
expense
|
69.4 | 57.4 | (46.2 | ) | 80.6 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
165.5 | 102.0 | (94.3 | ) | 173.2 | |||||||||||
|
Income
taxes
|
71.2 | (4.5 | ) | - | 66.7 | |||||||||||
|
NET
INCOME
|
$ | 94.3 | $ | 106.5 | $ | (94.3 | ) | $ | 106.5 | |||||||
Consolidating Statement of Cash
Flows for the year ended December 31, 2009 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 350.6 | $ | 6.2 | $ | - | $ | 356.8 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from
|
||||||||||||||||
|
Additional
capital contribution from parent
|
6.9 | 6.9 | (6.9 | ) | 6.9 | |||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
136.3 | 99.5 | (74.5 | ) | 161.3 | |||||||||||
|
Requirements for:
|
||||||||||||||||
|
Dividends to
parent
|
(82.5 | ) | (82.5 | ) | 82.5 | (82.5 | ) | |||||||||
|
Retirement of long-term
debt, including premiums paid
|
(3.0 | ) | (3.0 | ) | 3.0 | (3.0 | ) | |||||||||
|
Net
change in intercompany short-term borrowings
|
(152.5 | ) | (35.1 | ) | 187.6 | - | ||||||||||
|
Net
change in short-term borrowings
|
(0.4 | ) | (175.1 | ) | - | (175.5 | ) | |||||||||
|
Net cash flows from financing activities
|
(95.2 | ) | (189.3 | ) | 191.7 | (92.8 | ) | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from
|
||||||||||||||||
|
Consolidated
subsidiary distributions
|
- | 82.5 | (82.5 | ) | - | |||||||||||
|
Other
investing activities
|
- | 0.2 | - | 0.2 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital expenditures,
excluding AFUDC equity
|
(291.0 | ) | (15.9 | ) | - | (306.9 | ) | |||||||||
|
Consolidated subsidiary
investments
|
- | (6.9 | ) | 6.9 | - | |||||||||||
|
Other investing
activities
|
(3.6 | ) | - | - | (3.6 | ) | ||||||||||
|
Net
change in long-term intercompany notes receivable
|
- | (71.5 | ) | 71.5 | - | |||||||||||
|
Net
change in short-term intercompany notes receivable
|
35.1 | 152.5 | (187.6 | ) | - | |||||||||||
|
Net cash flows from investing activities
|
(259.5 | ) | 140.9 | (191.7 | ) | (310.3 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
(4.1 | ) | (42.2 | ) | - | (46.3 | ) | |||||||||
|
Cash
& cash equivalents at beginning of period
|
9.7 | 42.8 | - | 52.5 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 5.6 | $ | 0.6 | $ | - | $ | 6.2 | ||||||||
Consolidating Statement of Cash
Flows for the year ended December 31, 2008 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 379.6 | $ | 55.4 | $ | - | $ | 435.0 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
171.1 | 111.1 | (111.1 | ) | 171.1 | |||||||||||
|
Issuance of
common stock
|
- | 124.8 | - | 124.8 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Dividends to
parent
|
(83.2 | ) | (83.2 | ) | 83.2 | (83.2 | ) | |||||||||
|
Retirement of long-term
debt, including premiums paid
|
(104.6 | ) | (1.6 | ) | 1.6 | (104.6 | ) | |||||||||
|
Net
change in intercompany short-term borrowings
|
(80.9 | ) | 103.9 | (23.0 | ) | - | ||||||||||
|
Net
change in short-term borrowings
|
0.4 | (194.4 | ) | - | (194.0 | ) | ||||||||||
|
Net cash flows from financing activities
|
(97.2 | ) | 60.6 | (49.3 | ) | (85.9 | ) | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from:
|
||||||||||||||||
|
Consolidated
subsidiary distributions
|
- | 83.2 | (83.2 | ) | - | |||||||||||
|
Other
investing activities
|
2.3 | 0.2 | - | 2.5 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital expenditures,
excluding AFUDC equity
|
(277.0 | ) | (29.3 | ) | - | (306.3 | ) | |||||||||
|
Other investing
activities
|
(4.5 | ) | - | - | (4.5 | ) | ||||||||||
|
Net
change in long-term intercompany notes receivable
|
- | (109.5 | ) | 109.5 | - | |||||||||||
|
Net
change in short-term intercompany notes receivable
|
- | (23.0 | ) | 23.0 | - | |||||||||||
|
Net cash flows from investing activities
|
(279.2 | ) | (78.4 | ) | 49.3 | (308.3 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
3.2 | 37.6 | - | 40.8 | ||||||||||||
|
Cash
& cash equivalents at beginning of period
|
6.5 | 5.2 | - | 11.7 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
Consolidating Statement of Cash
Flows for the year ended December 31, 2007 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET
CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 211.2 | $ | 21.0 | $ | - | $ | 232.2 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Long-term debt
- net of issuance costs & hedging proceeds
|
30.3 | - | (14.0 | ) | 16.3 | |||||||||||
|
Additional
capital contribution
|
- | 5.3 | - | 5.3 | ||||||||||||
|
Requirements
for:
|
||||||||||||||||
|
Dividends to
parent
|
(76.4 | ) | (76.6 | ) | 76.4 | (76.6 | ) | |||||||||
|
Retirement of long-term
debt, including premiums paid
|
(6.5 | ) | - | - | (6.5 | ) | ||||||||||
|
Net
change in short-term borrowings, including from other
|
||||||||||||||||
|
Vectren
companies
|
110.3 | 115.8 | (110.3 | ) | 115.8 | |||||||||||
|
Net cash flows from financing activities
|
57.7 | 44.5 | (47.9 | ) | 54.3 | |||||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds
from:
|
||||||||||||||||
|
Consolidated
subsidiary distributions
|
- | 76.4 | (76.4 | ) | - | |||||||||||
|
Other
investing activities
|
0.7 | 0.3 | - | 1.0 | ||||||||||||
|
Requirements
for:
|
||||||||||||||||
|
Capital expenditures,
excluding AFUDC equity
|
(267.0 | ) | (35.5 | ) | - | (302.5 | ) | |||||||||
|
Consolidated subsidiary
investments
|
- | (14.0 | ) | 14.0 | - | |||||||||||
|
Unconsolidated affiliate
& other investments
|
(1.8 | ) | - | - | (1.8 | ) | ||||||||||
|
Net
change in notes receivable from other Vectren companies
|
- | (110.3 | ) | 110.3 | - | |||||||||||
|
Net cash flows from investing activities
|
(268.1 | ) | (83.1 | ) | 47.9 | (303.3 | ) | |||||||||
|
Net
change in cash & cash equivalents
|
0.8 | (17.6 | ) | - | (16.8 | ) | ||||||||||
|
Cash
& cash equivalents at beginning of period
|
5.7 | 22.8 | - | 28.5 | ||||||||||||
|
Cash
& cash equivalents at end of period
|
$ | 6.5 | $ | 5.2 | $ | - | $ | 11.7 | ||||||||
Consolidating Balance Sheet
as of December 31, 2009 (in millions):
|
ASSETS
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Assets
|
||||||||||||||||
|
Cash
& cash equivalents
|
$ | 5.6 | $ | 0.6 | - | $ | 6.2 | |||||||||
|
Accounts
receivable - less reserves
|
108.1 | - | - | 108.1 | ||||||||||||
|
Intercompany
receivables
|
68.2 | 132.7 | (200.9 | ) | - | |||||||||||
|
Receivables
due from other Vectren companies
|
0.7 | - | - | 0.7 | ||||||||||||
|
Accrued
unbilled revenues
|
115.4 | - | - | 115.4 | ||||||||||||
|
Inventories
|
124.6 | 3.3 | - | 127.9 | ||||||||||||
|
Recoverable
fuel & natural gas costs
|
- | - | - | - | ||||||||||||
|
Prepayments
& other current assets
|
63.4 | 16.4 | (10.6 | ) | 69.2 | |||||||||||
|
Total
current assets
|
486.0 | 153.0 | (211.5 | ) | 427.5 | |||||||||||
|
Utility
Plant
|
||||||||||||||||
|
Original
cost
|
4,601.4 | - | - | 4,601.4 | ||||||||||||
|
Less: accumulated
depreciation & amortization
|
1,722.6 | - | - | 1,722.6 | ||||||||||||
|
Net
utility plant
|
2,878.8 | - | - | 2,878.8 | ||||||||||||
|
Investments
in consolidated subsidiaries
|
- | 1,190.3 | (1,190.3 | ) | - | |||||||||||
|
Notes
receivable from consolidated subsidiaries
|
- | 770.4 | (770.4 | ) | - | |||||||||||
|
Investments
in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other
investments
|
26.0 | 5.4 | - | 31.4 | ||||||||||||
|
Nonutility
property - net
|
4.1 | 167.7 | - | 171.8 | ||||||||||||
|
Goodwill
- net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory
assets
|
79.6 | 24.5 | - | 104.1 | ||||||||||||
|
Other
assets
|
15.2 | - | (10.9 | ) | 4.3 | |||||||||||
|
TOTAL
ASSETS
|
$ | 3,694.9 | $ | 2,311.3 | $ | (2,183.1 | ) | $ | 3,823.1 | |||||||
|
LIABILITIES & SHAREHOLDER'S
EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Liabilities
|
||||||||||||||||
|
Accounts
payable
|
$ | 127.5 | $ | 5.6 | $ | - | $ | 133.1 | ||||||||
|
Accounts
payable to affiliated companies
|
54.1 | - | - | 54.1 | ||||||||||||
|
Intercompany
payables
|
18.2 | - | (18.2 | ) | - | |||||||||||
|
Payables
to other Vectren companies
|
53.6 | - | - | 53.6 | ||||||||||||
|
Refundable
fuel & natural gas costs
|
22.3 | - | - | 22.3 | ||||||||||||
|
Accrued
liabilities
|
120.8 | 21.2 | (10.6 | ) | 131.4 | |||||||||||
|
Short-term
borrowings
|
- | 16.4 | - | 16.4 | ||||||||||||
|
Intercompany
short-term borrowings
|
113.8 | 68.9 | (182.7 | ) | - | |||||||||||
|
Long-term
debt subject to tender
|
51.3 | - | - | 51.3 | ||||||||||||
|
Total
current liabilities
|
561.6 | 112.1 | (211.5 | ) | 462.2 | |||||||||||
|
Long-Term
Debt
|
||||||||||||||||
|
Long-term
debt - net of current maturities &
|
||||||||||||||||
|
debt
subject to tender
|
335.6 | 919.2 | - | 1,254.8 | ||||||||||||
|
Long-term
debt due to VUHI
|
770.4 | - | (770.4 | ) | - | |||||||||||
|
Total
long-term debt - net
|
1,106.0 | 919.2 | (770.4 | ) | 1,254.8 | |||||||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred
income taxes
|
417.8 | 0.2 | - | 418.0 | ||||||||||||
|
Regulatory
liabilities
|
318.2 | 4.0 | - | 322.2 | ||||||||||||
|
Deferred
credits & other liabilities
|
101.0 | 1.1 | (10.9 | ) | 91.2 | |||||||||||
|
Total
deferred credits & other liabilities
|
837.0 | 5.3 | (10.9 | ) | 831.4 | |||||||||||
|
Common
Shareholder's Equity
|
||||||||||||||||
|
Common
stock (no par value)
|
783.1 | 769.9 | (783.1 | ) | 769.9 | |||||||||||
|
Retained
earnings
|
407.1 | 504.7 | (407.1 | ) | 504.7 | |||||||||||
|
Accumulated
other comprehensive income
|
0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
|
Total
common shareholder's equity
|
1,190.3 | 1,274.7 | (1,190.3 | ) | 1,274.7 | |||||||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,694.9 | $ | 2,311.3 | $ | (2,183.1 | ) | $ | 3,823.1 | |||||||
Consolidating Balance Sheet
as of December 31, 2008 (in millions):
|
ASSETS
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Assets
|
||||||||||||||||
|
Cash
& cash equivalents
|
$ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
|
Accounts
receivable - less reserves
|
163.5 | 0.5 | - | 164.0 | ||||||||||||
|
Intercompany
receivables
|
104.2 | 275.9 | (380.1 | ) | - | |||||||||||
|
Receivables
due from other Vectren companies
|
4.5 | 0.2 | - | 4.7 | ||||||||||||
|
Accrued
unbilled revenues
|
167.2 | - | - | 167.2 | ||||||||||||
|
Inventories
|
78.7 | 5.9 | - | 84.6 | ||||||||||||
|
Recoverable
fuel & natural gas costs
|
3.1 | - | - | 3.1 | ||||||||||||
|
Prepayments
& other current assets
|
82.9 | 38.5 | (18.3 | ) | 103.1 | |||||||||||
|
Total
current assets
|
613.8 | 363.8 | (398.4 | ) | 579.2 | |||||||||||
|
Utility
Plant
|
||||||||||||||||
|
Original
cost
|
4,335.3 | - | - | 4,335.3 | ||||||||||||
|
Less: accumulated
depreciation & amortization
|
1,615.0 | - | - | 1,615.0 | ||||||||||||
|
Net
utility plant
|
2,720.3 | - | - | 2,720.3 | ||||||||||||
|
Investments
in consolidated subsidiaries
|
- | 1,167.4 | (1,167.4 | ) | - | |||||||||||
|
Notes
receivable from consolidated subsidiaries
|
- | 698.9 | (698.9 | ) | - | |||||||||||
|
Investments
in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other
investments
|
18.5 | 5.6 | - | 24.1 | ||||||||||||
|
Nonutility
property - net
|
4.3 | 178.1 | - | 182.4 | ||||||||||||
|
Goodwill
- net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory
assets
|
90.5 | 25.2 | - | 115.7 | ||||||||||||
|
Other
assets
|
14.2 | 0.2 | (3.2 | ) | 11.2 | |||||||||||
|
TOTAL
ASSETS
|
$ | 3,666.8 | $ | 2,439.2 | $ | (2,267.9 | ) | $ | 3,838.1 | |||||||
|
LIABILITIES & SHAREHOLDER'S
EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current
Liabilities
|
||||||||||||||||
|
Accounts
payable
|
$ | 205.5 | $ | 7.0 | $ | - | $ | 212.5 | ||||||||
|
Accounts
payable to affiliated companies
|
72.8 | - | - | 72.8 | ||||||||||||
|
Intercompany
payables
|
9.5 | 0.4 | (9.9 | ) | - | |||||||||||
|
Payables
to other Vectren companies
|
53.6 | 15.4 | - | 69.0 | ||||||||||||
|
Refundable
fuel & natural gas costs
|
4.1 | - | - | 4.1 | ||||||||||||
|
Accrued
liabilities
|
146.4 | 19.6 | (18.3 | ) | 147.7 | |||||||||||
|
Short-term
borrowings
|
0.4 | 191.5 | - | 191.9 | ||||||||||||
|
Intercompany
short-term borrowings
|
266.3 | 103.9 | (370.2 | ) | - | |||||||||||
|
Long-term
debt subject to tender
|
80.0 | - | - | 80.0 | ||||||||||||
|
Total
current liabilities
|
838.6 | 337.8 | (398.4 | ) | 778.0 | |||||||||||
|
Long-Term
Debt
|
||||||||||||||||
|
Long-term
debt - net of current maturities &
|
||||||||||||||||
|
debt
subject to tender
|
243.1 | 822.0 | - | 1,065.1 | ||||||||||||
|
Long-term
debt due to VUHI
|
698.9 | - | (698.9 | ) | - | |||||||||||
|
Total
long-term debt - net
|
942.0 | 822.0 | (698.9 | ) | 1,065.1 | |||||||||||
|
Deferred
Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred
income taxes
|
308.9 | 23.2 | - | 332.1 | ||||||||||||
|
Regulatory
liabilities
|
310.4 | 4.7 | - | 315.1 | ||||||||||||
|
Deferred
credits & other liabilities
|
99.5 | 8.6 | (3.2 | ) | 104.9 | |||||||||||
|
Total
deferred credits & other liabilities
|
718.8 | 36.5 | (3.2 | ) | 752.1 | |||||||||||
|
Common
Shareholder's Equity
|
||||||||||||||||
|
Common
stock (no par value)
|
776.3 | 763.0 | (776.3 | ) | 763.0 | |||||||||||
|
Retained
earnings
|
391.0 | 479.8 | (391.0 | ) | 479.8 | |||||||||||
|
Accumulated
other comprehensive income
|
0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
|
Total
common shareholder's equity
|
1,167.4 | 1,242.9 | (1,167.4 | ) | 1,242.9 | |||||||||||
|
TOTAL
LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,666.8 | $ | 2,439.2 | $ | (2,267.9 | ) | $ | 3,838.1 | |||||||
|
18.
|
Quarterly
Financial Data (Unaudited)
|
Information
in any one quarterly period is not indicative of annual results due to the
seasonal variations common to the Company’s utility
operations. Summarized quarterly financial data for 2009 and 2008
follows:
|
(In
millions)
|
Q1 | Q2 | Q3 | Q4 | ||||||||||||
|
2009
|
||||||||||||||||
|
Results
of Operations:
|
||||||||||||||||
|
Operating
revenues
|
$ | 652.8 | $ | 272.2 | $ | 236.8 | $ | 434.4 | ||||||||
|
Operating
income
|
105.2 | 27.6 | 32.1 | 73.1 | ||||||||||||
|
Net
income
|
56.2 | 6.6 | 8.7 | 35.9 | ||||||||||||
|
2008
|
||||||||||||||||
|
Results
of Operations:
|
||||||||||||||||
|
Operating
revenues
|
$ | 761.4 | $ | 352.7 | $ | 292.4 | $ | 552.2 | ||||||||
|
Operating
income
|
112.5 | 31.1 | 41.0 | 70.0 | ||||||||||||
|
Net
income
|
58.0 | 8.8 | 13.6 | 30.7 | ||||||||||||
ITEM
9. CHANGE IN & DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING & FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS & PROCEDURES
Changes in Internal Controls
over Financial Reporting
During
the quarter ended December 31, 2009, there have been no changes to the Company’s
internal controls over financial reporting that have materially affected, or are
reasonably likely to materially affect, the Company’s internal control over
financial reporting.
Conclusion Regarding the
Effectiveness of Disclosure Controls and Procedures
As of
December 31, 2009, the Company conducted an evaluation under the supervision and
with the participation of the Chief Executive Officer and Chief Financial
Officer of the effectiveness and the design and operation of the Company's
disclosure controls and procedures. Based on that evaluation, the
Chief Executive Officer and the Chief Financial Officer have concluded that the
Company's disclosure controls and procedures are effective as of December 31,
2009, to ensure that information required to be disclosed in reports filed or
submitted under the Exchange Act is:
|
1)
|
recorded,
processed, summarized and reported within the time periods specified in
the SEC’s rules and forms, and
|
|
|
2)
|
accumulated
and communicated to management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
|
Management’s Report on
Internal Control over Financial Reporting
Vectren
Utility Holdings, Inc.’s management is responsible for establishing and
maintaining adequate internal control over financial reporting. Under
the supervision and with the participation of management, including the Chief
Executive Officer and Chief Financial Officer, the Company conducted an
evaluation of the effectiveness of its internal control over financial reporting
based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on that evaluation under the framework in
Internal Control — Integrated
Framework, the Company concluded that its internal control over financial
reporting was effective as of December 31, 2009.
This
annual report does not include an attestation report of Utility Holdings’
registered public accounting firm regarding internal control over financial
reporting. Management's report was not subject to attestation by
Utility Holdings’ registered public accounting firm pursuant to temporary rules
of the Securities and Exchange Commission that permit Utility Holdings to
provide only management's report in this annual report.
ITEM 9B. OTHER INFORMATION
None.
PART
III
ITEM
10. DIRECTORS, EXECUTIVE OFFICERS & CORPORATE
GOVERNANCE
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
Vectren’s
Corporate Governance Guidelines, its charters for each of its Audit,
Compensation and Benefits and Nominating and Corporate Governance Committees,
and its Corporate Code of Conduct that covers the Company’s directors, officers
and employees are available in the Corporate Governance section of the Company’s
website, www.vectren.com. The
Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific
codes of ethics pertaining to the CEO and senior financial officers and the
Board of Directors in Exhibits D and E, respectively. A copy will be
mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren
Square, Evansville, Indiana 47708. The Company intends to disclose
any amendments to the Corporate Code of Conduct or waivers of the Corporate Code
of Conduct on behalf of the Company’s directors or officers including, but not
limited to, the principal executive officer, principal financial officer,
principal accounting officer and persons performing similar functions on the
Company’s website at the internet address set forth above promptly following the
date of such amendment or waiver and such information will also be available by
mail upon request to the address listed above.
ITEM 11. EXECUTIVE COMPENSATION
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
& MANAGEMENT & RELATED
STOCKHOLDER MATTERS
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
ITEM 13. CERTAIN RELATIONSHIPS & RELATED TRANSACTIONS
& DIRECTOR INDEPENDENCE
Intentionally
omitted. See the table of contents of this Annual Report on Form 10-K
for explanation.
ITEM 14. PRINCIPAL ACCOUNTANT FEES &
SERVICES
The
following tabulation shows the audit and non-audit fees incurred and payable to
Deloitte & Touche LLP (Deloitte) for the years ending December 31, 2009 and
2008. The fees presented below represent total Vectren fees, the
majority of which are allocated to Utility Holdings.
|
2009
|
2008
|
|||||||
|
Audit
Fees(1)
|
$ | 1,374,906 | $ | 1,378,911 | ||||
|
Audit-Related
Fees(2)
|
283,413 | 235,449 | ||||||
|
Tax
Fees(3)
|
122,145 | 162,073 | ||||||
|
Total
Fees Paid to Deloitte(4)
|
$ | 1,780,464 | $ | 1,776,433 | ||||
|
(1)
|
Aggregate
fees incurred and payable to Deloitte for professional services rendered
for the audits of Vectren’s and Utility Holdings’ 2009 and 2008
fiscal year annual financial statements and the review of financial
statements included in their Forms 10-K or 10-Q filed during the Company’s
2009 and 2008 fiscal years. The amount includes fees related to
the attestation to the Company’s assertion pursuant to Section 404 of
the Sarbanes-Oxley Act of 2002. In addition, this amount
includes the reimbursement of out-of-pocket costs incurred related to the
provision of these services totaling $104,406 and $69,911 in 2009 and
2008, respectively.
|
|
(2)
|
Audit-related
fees consisted principally of reviews related to various financing
transactions, regulatory filings, consultation on various accounting
issues, and audit fees related to the stand-alone audits of two of the
Company’s consolidated subsidiaries. In addition, this amount
includes the reimbursement of out-of-pocket costs incurred related to the
provision of these services totaling $15,013 and $5,949 in 2009 and 2008,
respectively.
|
|
(3)
|
Tax
fees consisted of fees paid to Deloitte for the review of tax returns and
consultation on other tax matters of the Company and of its consolidated
subsidiaries. In addition, this amount includes the
reimbursement of out-of-pocket costs incurred related to the provision of
these services totaling $13,205 and $17,548 in 2009 and 2008,
respectively.
|
|
(4)
|
Pursuant
to its charter, the Audit Committee is responsible for selecting,
approving professional fees and overseeing the independence,
qualifications and performance of the independent registered public
accounting firm. The Audit Committee has adopted a formal
policy with respect to the pre-approval of audit and permissible non-audit
services provided by the independent registered public accounting
firm. Pre-approval is assessed on a case-by-case
basis. In assessing requests for services to be provided by the
independent registered public accounting firm, the Audit Committee
considers whether such services are consistent with the auditors’
independence, whether the independent registered public accounting firm is
likely to provide the most effective and efficient service based upon the
firm’s familiarity with the Company, and whether the service could enhance
the Company’s ability to manage or control risk or improve audit
quality. The audit-related, tax and other services provided by
Deloitte in the last year and related fees were approved by the Audit
Committee in accordance with this
policy.
|
PART
IV
ITEM 15. EXHIBITS & FINANCIAL STATEMENT
SCHEDULES
List of Documents Filed as
Part of This Report
Consolidated Financial
Statements
The
consolidated financial statements and related notes, together with the report of
Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and
Supplementary Data” of this Form 10-K.
Supplemental
Schedules
For the
years ended December 31, 2009, 2008, and 2007, the Company’s Schedule II --
Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is
presented herein. The report of Deloitte & Touche LLP on the
schedule may be found in Item 8. All other schedules are omitted as
the required information is inapplicable or the information is presented in the
Consolidated Financial Statements or related notes in Item 8.
SCHEDULE
II
Vectren
Utility Holdings, Inc. and Subsidiaries
VALUATION
AND QUALIFYING ACCOUNTS AND RESERVES
|
Column
A
|
Column
B
|
Column
C
|
Column
D
|
Column
E
|
||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Balance
at
|
Charged
|
Charged
|
Deductions
|
Balance
at
|
||||||||||||||||
|
Beginning
|
to
|
to
Other
|
from
|
End
of
|
||||||||||||||||
|
Description
|
Of
Year
|
Expenses
|
Accounts
|
Reserves,
Net
|
Year
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
VALUATION
AND QUALIFYING ACCOUNTS:
|
||||||||||||||||||||
|
Year
2009 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 4.5 | $ | 14.6 | $ | - | $ | 15.1 | $ | 4.0 | ||||||||||
|
Year
2008 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 2.7 | $ | 15.8 | $ | - | $ | 14.0 | $ | 4.5 | ||||||||||
|
Year
2007 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 2.5 | $ | 15.0 | $ | - | $ | 14.8 | $ | 2.7 | ||||||||||
|
OTHER
RESERVES:
|
||||||||||||||||||||
|
Year
2009 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | 0.1 | $ | 0.5 | ||||||||||
|
Year
2008 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | - | $ | 0.6 | ||||||||||
|
Year
2007 – Restructuring costs
|
$ | 1.7 | $ | - | $ | - | $ | 1.1 | $ | 0.6 | ||||||||||
List of
Exhibits
The
Company has incorporated by reference herein certain exhibits as specified below
pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the
Company attached to this filing filed electronically with the SEC are listed
below.
Vectren
Utility Holdings, Inc.
Form
10-K
Attached
Exhibits
The
following Exhibits are included in this Annual Report on Form 10-K.
|
Exhibit
Number
|
Document
|
|
31.1
|
Chief
Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Chief
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
32
|
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
The
following Exhibits, as well as the Exhibits listed above, were filed
electronically with the SEC with this filing.
|
Exhibit
Number
|
Document
|
|
12
|
Ratio
of Earnings to Fixed Charges
|
|
21.1
|
List
of Company’s Significant Subsidiaries
|
|
23.1
|
Consent
of Independent Registered Public Accounting Firm
|
INDEX
TO EXHIBITS
3. Articles of
Incorporation and By-Laws
|
3.1
|
Articles
of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated
in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as
Exhibit 3.1)
|
|
3.2
|
Bylaws
of Vectren Utility Holdings, Inc. as most recently amended and restated as
of June 24, 2009 (Filed and designated in Current Report on Form 8-K filed
June 26, 2009, File No. 1-15467, as Exhibit
3.1.)
|
4. Instruments
Defining the Rights of Security Holders, Including
Indentures
|
4.1
|
Mortgage
and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas
and Electric Company and Bankers Trust Company, as Trustee, and
Supplemental Indentures thereto dated August 31, 1936, October 1, 1937,
March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1,
1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966,
August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1,
1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981,
January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November
1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed
and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in
Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit
(b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K,
File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated
March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3,
1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed
and designated in Form 10-K, for the fiscal year 1985, File
No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January
15, 1987. (Filed and designated in Form 10-K, for the fiscal
year 1986, File No. 1-3553, as Exhibit 4-A.) December 15,
1987. (Filed and designated in Form 10-K, for the fiscal year
1987, File No. 1-3553, as Exhibit 4-A.) December 13,
1990. (Filed and designated in Form 10-K, for the fiscal year
1990, File No. 1-3553, as Exhibit 4-A.) April 1,
1993. (Filed and designated in Form 8-K, dated April 13, 1993,
File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and
designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit
4.) May 1, 1993. (Filed and designated in Form 10-K,
for the fiscal year 1993, File No. 1-3553, as Exhibit
4(a).) July 1, 1999. (Filed and designated in Form
10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit
4(a).) March 1, 2000. (Filed and designated in Form
10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit
4.1.) August 1, 2004. (Filed and designated in Form 10-K for
the year ended December 31, 2004, File No. 1-15467, as Exhibit
4.1.) October 1, 2004. (Filed and designated in Form
10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit
4.2.) April 1, 2005 (Filed and designated in Form 10-K for the
year ended December 31, 2007, File No 1-15467, as Exhibit
4.1) March 1, 2006 (Filed and designated in Form 10-K for the
year ended December 31, 2007, File No 1-15467, as Exhibit
4.2) December 1, 2007 (Filed and designated in Form 10-K for
the year ended December 31, 2007, File No 1-15467, as Exhibit
4.3) August 1, 2009 (Filed and designated in Form 10-K for the
year ended December 31, 2009, File No 1-15467, as Exhibit
4.1)
|
|
4.2
|
Indenture
dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National
Association (formerly know as First Trust National Association, which was
formerly know as Bank of America Illinois, which was formerly know as
Continental Bank, National Association. Inc.'s. (Filed and
designated in Current Report on Form 8-K filed February 15, 1991, File No.
1-6494.); First Supplemental Indenture thereto dated as of February 15,
1991. (Filed and designated in Current Report on Form 8-K filed
February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental
Indenture thereto dated as of September 15, 1991, (Filed and designated in
Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as
Exhibit 4(b).); Third supplemental Indenture thereto dated as of September
15, 1991 (Filed and designated in Current Report on Form 8-K filed
September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth
Supplemental Indenture thereto dated as of December 2, 1992, (Filed and
designated in Current Report on Form 8-K filed December 8, 1992, File No.
1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as
of December 28, 2000, (Filed and designated in Current Report on Form 8-K
filed December 27, 2000, File No. 1-6494, as Exhibit
4.)
|
|
4.3
|
Indenture
dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association.
(Filed and designated in Form 8-K, dated October 19, 2001, File No.
1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19,
2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery of
Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental
Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery
of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit
4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated November 18,
2005, File No. 1-16739, as Exhibit 4.1). Form of Fifth
Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas & Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated October 16, 2006, File No. 1-16739, as
Exhibit 4.1). Sixth Supplemental Indenture, dated March 10,
2008, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery of
Ohio, Inc., and U.S. Bank National Association (Filed and designated in
Form 8-K, dated March 10, 2008, File No. 1-16739, as Exhibit
4.1)
|
|
4.4
|
Note
Purchase Agreement, dated April 7, 2009, among Vectren Utility Holdings,
Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company
and Vectren Energy Delivery of Ohio, Inc. and the purchasers named
therein. (Filed and designated in Form 8-K dated April 7, 2009 File No.
1-15467, as Exhibit 4.5)
|
10.
Material Contracts
|
10.1
|
Summary
description of Southern Indiana Gas and Electric Company's nonqualified
Supplemental Retirement Plan (Filed and designated in Form 10-K for the
fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First
Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for
the fiscal year 1997, File No. 1-3553, as Exhibit
10.29.).
|
|
10.2
|
Southern
Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and
designated in Southern Indiana Gas and Electric Company's Proxy Statement
dated February 22, 1994, File No. 1-3553, as Exhibit
A.)
|
|
10.3
|
Vectren
Corporation At Risk Compensation Plan effective May 1, 2001,(as amended
and restated s of May 1, 2006). (Filed and designated in
Vectren Corporation’s Proxy Statement dated March 15, 2006, File No.
1-15467, as Appendix H.)
|
|
10.4
|
Vectren
Corporation Non-Qualified Deferred Compensation Plan, as amended and
restated effective January 1, 2001. (Filed and designated in
Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as
Exhibit 10.32.)
|
|
10.5
|
Vectren
Corporation Nonqualified Deferred Compensation Plan, effective January 1,
2005. (Filed and designated in Form 8-K dated September 29,
2008, File No. 1-15467, as Exhibit
10.3.)
|
|
10.6
|
Vectren
Corporation Unfunded Supplemental Retirement Plan for a Select Group of
Management Employees (As Amended and Restated Effective January 1,
2005).(Filed and designated in Form 8-K dated December 17, 2008, File No.
1-15467, as Exhibit 10.1.)
|
|
10.7
|
Vectren
Corporation Nonqualified Defined Benefit Restoration Plan (As Amended and
Restated Effective January 1, 2005). (Filed and designated in Form 8-K
dated December 17, 2008, File No. 1-15467, as Exhibit
10.2.)
|
|
10.8
|
Vectren
Corporation Change in Control Agreement between Vectren Corporation and
Niel C. Ellerbrook dated as of March 1, 2005. (Filed and
designated in Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit
99.1.). Amendment Number One to the Vectren Corporation Change
in Control Agreement, effective as of March 1, 2005 between Vectren
Corporation and Niel C. Ellerbrook (Filed and designated in Form 8-K dated
September 29, 2008, File No. 1-15467, as Exhibit
10.1.)
|
|
10.9
|
Vectren
Corporation At Risk Compensation Plan specimen stock unit award agreement
for non-employee members of the Board of Directors, effective January 1,
2009. (Filed and designated in Form 8-K, dated February 20,
2009, File No. 1-15467, as Exhibit
10.1.)
|
|
10.10
|
Vectren
Corporation At Risk Compensation Plan specimen unit award agreement for
officers, effective January 1, 2010. (Filed and designated in
Form 8-K, dated January 7, 2010, File No. 1-15467, as Exhibit
10.1.)
|
|
10.11
|
Vectren
Corporation At Risk Compensation Plan specimen unit award agreement for
officers, effective January 1, 2009. (Filed and designated in
Form 8-K, dated February 17, 2009, File No. 1-15467, as Exhibit
10.1.)
|
|
10.12
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock grant
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.1.)
|
|
10.13
|
Vectren
Corporation At Risk Compensation Plan specimen restricted stock units
agreement for officers, effective January 1, 2008. (Filed and
designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as
Exhibit 99.2.)
|
|
10.14
|
Vectren
Corporation At Risk Compensation Plan specimen Stock Option Grant
Agreement for officers, effective January 1, 2005. (Filed and
designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as
Exhibit 99.2.)
|
|
10.15
|
Vectren
Corporation At Risk Compensation Plan stock unit award agreement for
non-employee directors, effective May 1, 2009. (Filed and designation in
Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit
10.1)
|
|
10.16
|
Vectren
Corporation specimen employment agreement dated February 1,
2005. (Filed and designated in Form 8-K, dated February 1,
2005, File No. 1-15467, as Exhibit 99.1.) Amendment Number One
to the Specimen Vectren Corporation Employment Agreement between Vectren
Corporation and Executive Officers (Filed and designated in Form 8-K dated
September 29, 2008, File No. 1-15467, as Exhibit 10.2.) The specimen
agreements and related amendments differ among named executive officers
only to the extent severance and change in control benefits are
provided in the amount of three times base salary and bonus for Messrs.
Benkert, Chapman, and Christian and two times for Mr.
Doty.
|
|
10.17
|
Coal
Supply Agreement for Warrick 4 Generating Station between Southern Indiana
Gas and Electric Company and Vectren Fuels, Inc., effective January 1,
2009. (Filed and designated in Form 8-K dated January 5, 2009,
File No. 1-15467, as Exhibit 10.1.)
|
|
10.18
|
Coal
Supply Agreement for F.B. Culley Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., effective
January 1, 2009. (Filed and designated in Form 8-K dated
January 5, 2009, File No. 1-15467, as Exhibit
10.2.)
|
|
10.19
|
Coal
Supply Agreement for A.B. Brown Generating Station for 410,000 tons
between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc.,
effective January 1, 2009. (Filed and designated in Form 8-K
dated January 5, 2009, File No. 1-15467, as Exhibit
10.3.)
|
|
10.20
|
Coal
Supply Agreement for A.B. Brown Generating Station for 1 million tons
between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc.,
effective January 1, 2009. (Filed and designated in Form 8-K
dated January 5, 2009, File No. 1-15467, as Exhibit
10.4.)
|
|
10.21
|
Amendment
to F.B. Culley and A.B. Brown Coal Supply Agreements dated December 21,
2009. (Filed and designated in Form 10-K, for the year ended December 31,
2009, File No. 1-15467, as exhibit
10.1)
|
|
10.22
|
Gas
Sales and Portfolio Administration Agreement between Indiana Gas Company,
Inc. and ProLiance Energy, LLC, effective August 30,
2003. (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No. 1-15467, as Exhibit
10.15.)
|
|
10.23
|
Gas
Sales and Portfolio Administration Agreement between Southern Indiana Gas
and Electric Company and ProLiance Energy, LLC, effective September 1,
2002. (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No. 1-15467, as Exhibit
10.16.)
|
|
10.24
|
Formation
Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC
Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group,
Citizens Energy Services Corporation and ProLiance Energy, LLC, effective
March 15, 1996. (Filed and designated in Form 10-Q for the
quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit
10-C.)
|
|
10.25
|
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among Vectren
Utility Holdings, Inc., and each of the purchasers named
therein. (Filed and designated in Form 10-Q, for the period
ended September 30, 2009, File No. 1-15467, as Exhibit
10.24.)
|
|
10.26
|
Niel
C. Ellerbrook Retirement Agreement, dated February 3,
2010. (Filed and designated in Form 8-K dated February 4, 2010
File No. 1-15467, as Exhibit 99.2)
|
21.
Subsidiaries of the Company
The list
of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.
(Filed
herewith.)
23.
Consent of Experts and Counsel
The
consent of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 (Filed
herewith.)
31.
Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of
2002
Chief
Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)
Chief
Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act Of 2002 is attached hereto as Exhibit 31.2 (Filed
herewith.)
32.
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act
Of 2002 is attached hereto as Exhibit 32 (Filed herewith.)99.
Additional Exhibits
99.1 Amended
and Restated Articles of Incorporation of Vectren Corporation effective March
31, 2000. (Filed and designated in Current Report on Form 8-K filed
April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
99.2
Amended
and Restated Code of By-Laws of Vectren Corporation as of March 3, 2010. (Filed
and designated in Current Report on Form 8-K filed March 4, 2010, File No.
1-15467, as Exhibit 3.1.)
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
VECTREN
UTILITY HOLDINGS, INC.
Dated
March 5,
2010 /s/ Niel C.
Ellerbrook
Niel C.
Ellerbrook,
Chairman,
Chief Executive Officer and Director
Pursuant
to the requirements of the Securities and Exchange Act of 1934, this report has
been signed below by the following persons on behalf of the Registrant and in
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||
|
/s/
Niel C. Ellerbrook
|
Chairman,
Chief Executive Officer and Director
|
March
5, 2010
|
||
|
Niel
C. Ellerbrook
|
(Principal
Executive Officer)
|
|||
|
/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President and Chief Financial Officer
|
March
5, 2010
|
||
|
Jerome
A. Benkert, Jr.
|
(Principal
Financial Officer)
|
|||
|
/s/ M.
Susan Hardwick
|
Vice
President, Controller and Assistant Treasurer
|
March
5, 2010
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
|
/s/
Ronald E. Christian
|
Director
|
March
5, 2010
|
||
|
Ronald
E. Christian
|
||||
|
/s/
William S. Doty
|
Director
|
March
5, 2010
|
||
|
William
S. Doty
|
-82-
|