vvc_10q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
x
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the quarterly period ended March 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: 1-15467
(Exact
name of registrant as specified in its charter)
INDIANA
|
|
35-2086905
|
(State
or other jurisdiction of incorporation or organization)
|
|
(IRS
Employer Identification No.)
|
One
Vectren Square, Evansville, IN
47708
|
(Address
of principal executive offices)
(Zip
Code)
(Registrant's
telephone number, including area code)
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. x
Yes □
No
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 x Accelerated
filer r
Non-accelerated
filer r (Do
not check if a smaller reporting
company) Smaller
reporting company r
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
□
Yes x No
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date.
Common Stock- Without Par
Value
|
81,041,060
|
April 30, 2009
|
Class
|
Number of Shares
|
Date
|
Access
to Information
Vectren
Corporation makes available all SEC filings and recent annual reports free of
charge through its website at www.vectren.com as
soon as reasonably practicable after electronically filing or furnishing the
reports to the SEC, or by request, directed to Investor Relations at the mailing
address, phone number, or email address that follows:
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
|
Definitions
AFUDC: allowance
for funds used during construction
|
MMBTU: millions
of British thermal units
|
APB: Accounting
Principles Board
|
MW: megawatts
|
EITF: Emerging
Issues Task Force
|
MWh
/ GWh: megawatt hours / thousands of megawatt hours (gigawatt
hours)
|
FASB: Financial
Accounting Standards Board
|
OCC: Ohio
Office of the Consumer Counselor
|
FERC: Federal
Energy Regulatory Commission
|
OUCC: Indiana
Office of the Utility Consumer Counselor
|
IDEM: Indiana
Department of Environmental Management
|
PUCO: Public
Utilities Commission of Ohio
|
IURC: Indiana
Utility Regulatory Commission
|
SFAS: Statement
of Financial Accounting Standards
|
MCF
/ BCF: thousands / billions of cubic feet
|
USEPA: United
States Environmental Protection Agency
|
MDth
/ MMDth: thousands / millions of dekatherms
|
Throughput: combined
gas sales and gas transportation volumes
|
MISO:
Midwest Independent System Operator
|
|
Item
Number
|
|
Page
Number
|
|
PART
I. FINANCIAL INFORMATION
|
|
1
|
Financial
Statements (Unaudited)
|
|
|
Vectren
Corporation and Subsidiary Companies
|
|
|
|
4-5
|
|
|
6
|
|
|
7
|
|
|
8
|
2
|
|
22
|
3
|
|
42
|
4
|
|
43
|
|
|
|
|
PART
II. OTHER INFORMATION
|
|
1
|
|
43
|
1A
|
|
43
|
2
|
|
43
|
6
|
|
43
|
|
|
44
|
PART
I. FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
CONDENSED BALANCE SHEETS
(Unaudited – In
millions)
|
|
|
|
|
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash
& cash equivalents
|
|
$ |
19.4 |
|
|
$ |
93.2 |
|
Accounts
receivable - less reserves of $6.1 &
|
|
|
|
|
|
|
|
|
$5.6,
respectively
|
|
|
214.9 |
|
|
|
226.7 |
|
Accrued
unbilled revenues
|
|
|
83.0 |
|
|
|
197.0 |
|
Inventories
|
|
|
92.7 |
|
|
|
131.0 |
|
Recoverable
fuel & natural gas costs
|
|
|
- |
|
|
|
3.1 |
|
Prepayments
& other current assets
|
|
|
40.8 |
|
|
|
124.6 |
|
Total
current assets
|
|
|
450.8 |
|
|
|
775.6 |
|
|
|
|
|
|
|
|
|
|
Utility
Plant
|
|
|
|
|
|
|
|
|
Original
cost
|
|
|
4,411.2 |
|
|
|
4,335.3 |
|
Less: accumulated
depreciation & amortization
|
|
|
1,642.7 |
|
|
|
1,615.0 |
|
Net
utility plant
|
|
|
2,768.5 |
|
|
|
2,720.3 |
|
|
|
|
|
|
|
|
|
|
Investments
in unconsolidated affiliates
|
|
|
164.9 |
|
|
|
179.1 |
|
Other
utility & corporate investments
|
|
|
26.6 |
|
|
|
25.7 |
|
Other
nonutility investments
|
|
|
46.0 |
|
|
|
45.9 |
|
Nonutility
property - net
|
|
|
410.3 |
|
|
|
390.2 |
|
Goodwill
- net
|
|
|
240.3 |
|
|
|
240.2 |
|
Regulatory
assets
|
|
|
203.1 |
|
|
|
216.7 |
|
Other
assets
|
|
|
35.1 |
|
|
|
39.2 |
|
TOTAL
ASSETS
|
|
$ |
4,345.6 |
|
|
$ |
4,632.9 |
|
The
accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
CONDENSED BALANCE SHEETS
(Unaudited – In
millions)
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
LIABILITIES & SHAREHOLDERS'
EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
131.3 |
|
|
$ |
266.1 |
|
Accounts
payable to affiliated companies
|
|
|
38.0 |
|
|
|
75.2 |
|
Refundable
fuel & natural gas costs
|
|
|
25.6 |
|
|
|
4.1 |
|
Accrued
liabilities
|
|
|
217.8 |
|
|
|
175.0 |
|
Short-term
borrowings
|
|
|
113.6 |
|
|
|
519.5 |
|
Current
maturities of long-term debt
|
|
|
0.4 |
|
|
|
0.4 |
|
Long-term
debt subject to tender
|
|
|
80.0 |
|
|
|
80.0 |
|
Total
current liabilities
|
|
|
606.7 |
|
|
|
1,120.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
Debt - Net of Current Maturities &
|
|
|
|
|
|
|
|
|
Debt
Subject to Tender
|
|
|
1,438.6 |
|
|
|
1,247.9 |
|
|
|
|
|
|
|
|
|
|
Deferred
Income Taxes & Other Liabilities
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
357.0 |
|
|
|
353.4 |
|
Regulatory
liabilities
|
|
|
318.2 |
|
|
|
315.1 |
|
Deferred
credits & other liabilities
|
|
|
239.2 |
|
|
|
244.6 |
|
Total
deferred credits & other liabilities
|
|
|
914.4 |
|
|
|
913.1 |
|
|
|
|
|
|
|
|
|
|
Commitments
& Contingencies (Notes 7, 9-11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Shareholders' Equity
|
|
|
|
|
|
|
|
|
Common
stock (no par value) – issued & outstanding
|
|
|
|
|
|
|
|
|
81.0
& 81.0, respectively
|
|
|
660.8 |
|
|
|
659.1 |
|
Retained
earnings
|
|
|
758.5 |
|
|
|
712.8 |
|
Accumulated
other comprehensive income (loss)
|
|
|
(33.4 |
) |
|
|
(20.3 |
) |
Total
common shareholders' equity
|
|
|
1,385.9 |
|
|
|
1,351.6 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES & SHAREHOLDERS' EQUITY
|
|
$ |
4,345.6 |
|
|
$ |
4,632.9 |
|
The
accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
CONDENSED STATEMENTS OF INCOME
(Unaudited – In millions, except per
share data)
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
|
|
2009
|
|
|
2008
|
|
OPERATING
REVENUES
|
|
|
|
|
|
|
Gas
utility
|
|
$ |
527.4 |
|
|
$ |
633.6 |
|
Electric
utility
|
|
|
125.0 |
|
|
|
127.2 |
|
Nonutility
revenues
|
|
|
142.8 |
|
|
|
141.3 |
|
Total
operating revenues
|
|
|
795.2 |
|
|
|
902.1 |
|
OPERATING
EXPENSES
|
|
|
|
|
|
|
|
|
Cost
of gas sold
|
|
|
354.6 |
|
|
|
462.0 |
|
Cost
of fuel & purchased power
|
|
|
47.0 |
|
|
|
46.0 |
|
Cost
of nonutility revenues
|
|
|
74.2 |
|
|
|
95.3 |
|
Other
operating
|
|
|
122.7 |
|
|
|
115.8 |
|
Depreciation
& amortization
|
|
|
51.4 |
|
|
|
47.4 |
|
Taxes
other than income taxes
|
|
|
23.5 |
|
|
|
26.8 |
|
Total
operating expenses
|
|
|
673.4 |
|
|
|
793.3 |
|
OPERATING
INCOME
|
|
|
121.8 |
|
|
|
108.8 |
|
OTHER
INCOME
|
|
|
|
|
|
|
|
|
Equity
in earnings of unconsolidated affiliates
|
|
|
12.6 |
|
|
|
14.0 |
|
Other
income – net
|
|
|
2.4 |
|
|
|
3.0 |
|
Total
other income
|
|
|
15.0 |
|
|
|
17.0 |
|
|
|
|
|
|
|
|
|
|
INTEREST
EXPENSE
|
|
|
22.7 |
|
|
|
25.3 |
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
114.1 |
|
|
|
100.5 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
41.3 |
|
|
|
36.5 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
72.8 |
|
|
$ |
64.0 |
|
|
|
|
|
|
|
|
|
|
AVERAGE
COMMON SHARES OUTSTANDING
|
|
|
80.6 |
|
|
|
76.0 |
|
DILUTED
COMMON SHARES OUTSTANDING
|
|
|
80.7 |
|
|
|
76.1 |
|
|
|
|
|
|
|
|
|
|
EARNINGS
PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
BASIC
|
|
$ |
0.90 |
|
|
$ |
0.84 |
|
DILUTED
|
|
$ |
0.90 |
|
|
$ |
0.84 |
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF
|
|
|
|
|
|
|
|
|
COMMON
STOCK
|
|
$ |
0.34 |
|
|
$ |
0.33 |
|
The
accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited – In
millions)
|
|
Three
Months Ended March 31,
|
|
|
|
2009
|
|
|
2008
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net
income
|
|
$ |
72.8 |
|
|
$ |
64.0 |
|
Adjustments to reconcile net income to cash from operating
activities:
|
|
Depreciation
& amortization
|
|
|
51.4 |
|
|
|
47.4 |
|
Deferred
income taxes & investment tax credits
|
|
|
11.3 |
|
|
|
12.7 |
|
Equity
in earnings of unconsolidated affiliates
|
|
|
(12.6 |
) |
|
|
(14.0 |
) |
Provision
for uncollectible accounts
|
|
|
4.3 |
|
|
|
5.3 |
|
Expense
portion of pension & postretirement periodic benefit
cost
|
|
|
2.6 |
|
|
|
1.9 |
|
Other
non-cash charges - net
|
|
|
1.0 |
|
|
|
2.0 |
|
Changes
in working capital accounts:
|
|
|
|
|
|
|
|
|
Accounts
receivable & accrued unbilled revenues
|
|
|
120.7 |
|
|
|
(26.8 |
) |
Inventories
|
|
|
38.8 |
|
|
|
96.8 |
|
Recoverable/refundable
fuel & natural gas costs
|
|
|
24.7 |
|
|
|
(3.4 |
) |
Prepayments
& other current assets
|
|
|
83.2 |
|
|
|
91.7 |
|
Accounts
payable, including to affiliated companies
|
|
|
(167.0 |
) |
|
|
(74.4 |
) |
Accrued
liabilities
|
|
|
43.4 |
|
|
|
84.3 |
|
Unconsolidated
affiliate dividends
|
|
|
4.3 |
|
|
|
2.9 |
|
Changes
in noncurrent assets
|
|
|
14.8 |
|
|
|
5.9 |
|
Changes
in noncurrent liabilities
|
|
|
(9.2 |
) |
|
|
(7.9 |
) |
Net
cash flows from operating activities
|
|
|
284.5 |
|
|
|
288.4 |
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
Proceeds
from:
|
|
|
|
|
|
|
|
|
Long-term
debt, net of issuance costs
|
|
|
191.2 |
|
|
|
171.5 |
|
Stock
option exercises & other
|
|
|
1.5 |
|
|
|
- |
|
Requirements
for:
|
|
|
|
|
|
|
|
|
Dividends
on common stock
|
|
|
(27.1 |
) |
|
|
(24.7 |
) |
Retirement
of long-term debt
|
|
|
(0.6 |
) |
|
|
(103.2 |
) |
Net
change in short-term borrowings
|
|
|
(405.9 |
) |
|
|
(251.9 |
) |
Net
cash flows from financing activities
|
|
|
(240.9 |
) |
|
|
(208.3 |
) |
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
Proceeds
from:
|
|
|
|
|
|
|
|
|
Other
collections
|
|
|
0.9 |
|
|
|
1.9 |
|
Requirements
for:
|
|
|
|
|
|
|
|
|
Capital
expenditures, excluding AFUDC equity
|
|
|
(117.4 |
) |
|
|
(69.6 |
) |
Unconsolidated
affiliate investments
|
|
|
(0.1 |
) |
|
|
(0.1 |
) |
Other
investments
|
|
|
(0.8 |
) |
|
|
(7.7 |
) |
Net
cash flows from investing activities
|
|
|
(117.4 |
) |
|
|
(75.5 |
) |
Net
change in cash & cash equivalents
|
|
|
(73.8 |
) |
|
|
4.6 |
|
Cash
& cash equivalents at beginning of period
|
|
|
93.2 |
|
|
|
20.6 |
|
Cash
& cash equivalents at end of period
|
|
$ |
19.4 |
|
|
$ |
25.2 |
|
The
accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
NOTES
TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1.
|
Organization
and Nature of Operations
|
Vectren
Corporation (the Company or Vectren), an Indiana corporation, is an energy
holding company headquartered in Evansville, Indiana. The Company’s
wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings),
serves as the intermediate holding company for three 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. Utility Holdings’ consolidated operations are collectively
referred to as the Utility Group. Both Vectren and Utility Holdings
are holding companies as defined by the Energy Policy Act of 2005 (Energy
Act). Vectren was incorporated under the laws of Indiana on June 10,
1999.
Indiana
Gas provides energy delivery services to over 567,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 111,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and
SIGECO generally do business as Vectren Energy Delivery of
Indiana. The Ohio operations provide energy delivery services to
approximately 317,000 natural gas customers located near Dayton in west central
Ohio. The Ohio operations are owned as a tenancy in common by Vectren
Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility
Holdings (53 percent ownership), and Indiana Gas (47 percent
ownership). The Ohio operations generally do business as Vectren
Energy Delivery of Ohio.
The
Company, through Vectren Enterprises, Inc. (Enterprises), is involved in
nonutility activities in three primary business areas: Energy
Marketing and Services, Coal Mining and Energy Infrastructure
Services. Energy Marketing and Services markets and supplies natural
gas and provides energy management services. Coal Mining mines and
sells coal. Energy Infrastructure Services provides underground
construction and repair services and performance contracting and renewable
energy services. Enterprises also has other legacy businesses that
have invested in energy-related opportunities and services, real estate, and
leveraged leases, among other investments. These operations are
collectively referred to as the Nonutility Group. Enterprises
supports the Company’s regulated utilities pursuant to service contracts by
providing natural gas supply services, coal, and infrastructure
services.
The
interim consolidated condensed financial statements included in this report have
been prepared by the Company, without audit, as provided in the rules and
regulations of the Securities and Exchange Commission. Certain
information and note disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the
United States have been omitted as provided in such rules and
regulations. The information in this report reflects all adjustments
which are, in the opinion of management, necessary to fairly state the interim
periods presented, inclusive of adjustments that are normal and recurring in
nature. These consolidated condensed financial statements and related
notes should be read in conjunction with the Company’s audited annual
consolidated financial statements for the year ended December 31, 2008, filed
with the Securities and Exchange Commission on February 19, 2009, on Form
10-K. Because of the seasonal nature of the Company’s utility
operations, the results shown on a quarterly basis are not necessarily
indicative of annual results.
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the statements
and the reported amounts of revenues and expenses during the reporting
periods. Actual results could differ from those
estimates.
Comprehensive
income consists of the following:
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
Net
income
|
|
$ |
72.8 |
|
|
$ |
64.0 |
|
Comprehensive
loss of unconsolidated affiliates
|
|
|
(21.9 |
) |
|
|
(10.1 |
) |
Cash
flow hedges
|
|
|
|
|
|
|
|
|
Unrealized
gains/(losses)
|
|
|
0.1 |
|
|
|
- |
|
Reclassifications
to net income
|
|
|
(0.1 |
) |
|
|
(0.2 |
) |
Income
tax benefit
|
|
|
8.9 |
|
|
|
4.0 |
|
Total
comprehensive income
|
|
$ |
59.8 |
|
|
$ |
57.7 |
|
Accumulated
other comprehensive income arising from unconsolidated affiliates is primarily
the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive
income related to use of cash flow hedges. (See Note 7 for more
information on ProLiance.)
Earnings
per share (EPS) is calculated in accordance with SFAS 128, “Earnings Per Share”
and its related interpretations. Basic earnings per share is computed
by dividing net income available to common shareholders by the weighted-average
number of common shares outstanding for the period. Diluted earnings
per share includes the impact of stock options and other equity based
instruments to the extent the effect is dilutive. The following table
illustrates the basic and dilutive earnings per share calculations for the
periods presented in these financial statements.
|
|
Three
Months Ended March 31,
|
|
(In
millions, except per share data)
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
Reported
net income
|
|
$ |
72.8 |
|
|
$ |
64.0 |
|
Less:
Income allocated to participating share-based securities
|
|
|
(0.2 |
) |
|
|
(0.2 |
) |
Reported
net income (Basic & Diluted EPS)
|
|
$ |
72.6 |
|
|
$ |
63.8 |
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding (Basic EPS)
|
|
|
80.6 |
|
|
|
76.0 |
|
Conversion
of stock options
|
|
|
0.1 |
|
|
|
0.1 |
|
Adjusted
weighted average shares outstanding and
|
|
|
|
|
|
|
|
|
assumed
conversions outstanding (Diluted EPS)
|
|
|
80.7 |
|
|
|
76.1 |
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share
|
|
$ |
0.90 |
|
|
$ |
0.84 |
|
Diluted
earnings per share
|
|
$ |
0.90 |
|
|
$ |
0.84 |
|
For the
three months ended March 31, 2009, options to purchase 837,100 additional shares
of the Company’s common stock were outstanding, but were not included in the
computation of diluted EPS because their effect would be
antidilutive. The exercise prices for these options ranged from
$23.19 to $27.15. For the three months ended March 31, 2008, all
options were dilutive. For the three months ended March 31, 2008, the
effect of an equity forward was antidilutive and was therefore excluded from the
calculation of diluted EPS.
Participating
Securities
On
January 1, 2009, the Company adopted FSP EITF 03-6-1, “Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating
Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1 clarified that
unvested share-based payment awards that contain rights to nonforfeitable
dividends participate in undistributed earnings with common
shareholders. Awards of this nature that impact the EPS calculation
are participating securities. The presence of a participating
security requires EPS to be calculated using the two-class method.
Of the
approximate 81 million shares outstanding as of March 31, 2009, unvested
share-based payment awards that contain rights to nonforfeitable dividends
comprise less than one percent. The Company recently prospectively
changed share-based payment awards such that dividends on awards granted in 2009
and beyond are subject to forfeiture.
As a
result of the insignificant level of participating securities subject to the
two-class method of computing earnings per share, the adoption of FSP EITF
03-6-1 had immaterial impacts to both current and prior period earnings per
share calculations.
5.
|
Excise
and Utility Receipts Taxes
|
Excise
taxes and a portion of utility receipts taxes are included in rates charged to
customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $15.9 million and $19.3 in the
three months ended March 31, 2009 and 2008, respectively. Expenses
associated with excise and utility receipts taxes are recorded as a component of
Taxes other than income
taxes.
6.
|
Retirement
Plans & Other Postretirement
Benefits
|
The
Company maintains three qualified defined benefit pension plans, a nonqualified
supplemental executive retirement plan (SERP), and three other postretirement
benefit plans. The qualified pension plans and the SERP are
aggregated under the heading “Pension Benefits.” Other postretirement
benefit plans are aggregated under the heading “Other Benefits.”
Net Periodic Benefit
Cost
A summary
of the components of net periodic benefit cost follows:
|
|
Three
Months Ended March 31,
|
|
|
|
Pension
Benefits
|
|
|
Other
Benefits
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Service
cost
|
|
$ |
1.6 |
|
|
$ |
1.5 |
|
|
$ |
0.1 |
|
|
$ |
0.1 |
|
Interest
cost
|
|
|
3.9 |
|
|
|
3.8 |
|
|
|
1.1 |
|
|
|
1.0 |
|
Expected
return on plan assets
|
|
|
(4.1 |
) |
|
|
(4.1 |
) |
|
|
(0.1 |
) |
|
|
(0.1 |
) |
Amortization
of prior service cost
|
|
|
0.4 |
|
|
|
0.4 |
|
|
|
(0.2 |
) |
|
|
(0.2 |
) |
Amortization
of transitional obligation
|
|
|
- |
|
|
|
- |
|
|
|
0.3 |
|
|
|
0.3 |
|
Amortization
of actuarial loss
|
|
|
0.6 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Net
periodic benefit cost
|
|
$ |
2.4 |
|
|
$ |
1.6 |
|
|
$ |
1.3 |
|
|
$ |
1.1 |
|
Employer Contributions to
Qualified Pension Plans
Currently,
the Company expects to contribute approximately $25 to $30 million to its
pension plan trusts for 2009. Through March 31, 2009, contributions
of $4.7 million have been made to the pension plan trusts.
7.
|
Transactions
with ProLiance Holdings, LLC
|
ProLiance
Holdings, LLC (ProLiance), a nonutility energy marketing
affiliate of Vectren and Citizens Energy Group (Citizens), provides services to
a broad range of municipalities, utilities, industrial operations, schools, and
healthcare institutions located throughout the Midwest and Southeast United
States. ProLiance’s customers include Vectren’s Indiana utilities and
nonutility gas supply operations as well as Citizens’
utilities. ProLiance’s primary businesses include gas marketing, gas
portfolio optimization, and other portfolio and energy management
services. Consistent with its ownership percentage, Vectren is
allocated 61 percent of ProLiance’s profits and losses; however, governance and
voting rights remain at 50 percent for each member; and therefore, the Company
accounts for its investment in ProLiance using the equity method of
accounting.
Summarized Financial
Information
Summarized
financial information related to ProLiance is presented below:
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
Summarized
statement of income information:
|
|
|
|
|
|
|
Revenues
|
|
$ |
658.8 |
|
|
$ |
809.6 |
|
Operating
income
|
|
|
21.3 |
|
|
|
23.3 |
|
ProLiance's
earnings
|
|
|
21.8 |
|
|
|
23.6 |
|
|
|
|
|
|
|
|
|
|
|
|
As
of March 31,
|
|
|
As
of December 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
Summarized
balance sheet information:
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
442.9 |
|
|
$ |
661.5 |
|
Noncurrent
assets
|
|
|
104.3 |
|
|
|
104.2 |
|
Current
liabilities
|
|
|
316.7 |
|
|
|
514.0 |
|
Noncurrent
liabilities
|
|
|
3.7 |
|
|
|
3.6 |
|
Members'
equity
|
|
|
310.5 |
|
|
|
295.8 |
|
Accumulated
other comprehensive income (loss)
|
|
|
(83.7 |
) |
|
|
(47.7 |
) |
Vectren
records its 61 percent share of ProLiance’s earnings after income taxes and an
interest expense allocation.
Regulatory
Matter
ProLiance
self reported to the Federal Energy Regulatory Commission (FERC) in October 2007
possible non-compliance with the FERC’s capacity release
policies. ProLiance has taken corrective actions to assure that
current and future transactions are compliant. ProLiance is committed
to full regulatory compliance and is cooperating fully with the FERC regarding
these issues. ProLiance believes that it has adequately reserved for
this matter. Although the outcome of any legal or regulatory proceedings
resulting from these matters cannot be predicted, the final resolution of these
matters is not expected to have a material impact on the Company’s consolidated
operating results, financial position or cash flows.
Investment in Liberty Gas
Storage
Liberty
Gas Storage, LLC (Liberty) is a joint venture between a subsidiary of ProLiance
and a subsidiary of Sempra Energy (SE). ProLiance is the minority member
with a 25 percent interest, which it accounts for using the equity method.
Liberty, as currently permitted, is a 17 BCF salt dome facility in southern
Louisiana, near Sulphur, Louisiana. Liberty also owns a second site near
Hackberry, Louisiana with the potential to develop an additional 17 BCF of
storage. ProLiance has a long term contract for approximately 5 Bcf of
working gas capacity. The total project cost incurred at the Sulphur
site through March 31, 2009 is approximately $200 million. ProLiance’s
portion of the cost incurred is approximately $50 million.
In late
2008, SE advised ProLiance that the completion of this phase of Liberty’s
development at the Sulphur site has been delayed by subsurface and
well-completion problems. To date, corrective measures have been
unsuccessful. Among other options, other corrective measures are being
evaluated but it is possible that the salt-cavern facility may not go into
service, or may have reduced capacity when placed in service. ProLiance
estimates the maximum exposure of its investment in the Sulphur site is $35
million. The Company’s proportionate share would be $12 million after
tax. The Company believes that such a charge, should it occur, would
not have a material adverse effect on either the Company’s or ProLiance’s
financial position, cash flows, or liquidity, but it could be material to net
income in any one accounting period. Further, it is not expected that the
delay in Liberty’s development will impact ProLiance’s ability to meet the needs
of its customers.
Transactions with
ProLiance
Purchases
from ProLiance for resale and for injections into storage for the three months
ended March 31, 2009 and 2008 totaled $202.9 million and $289.4 million,
respectively. Amounts owed to ProLiance at March 31, 2009, and
December 31, 2008, for those purchases were $38.0 million and $75.1 million,
respectively, and are included in Accounts payable to affiliated
companies. Vectren received regulatory approval on April 25,
2006, from the IURC for ProLiance to provide natural gas supply services to the
Company’s Indiana utilities through March 2011.
Amounts
charged by ProLiance for gas supply services are established by supply
agreements with each utility.
8.
|
2009
Long-Term Debt Transactions
|
Post March 31, 2009 Utility
Holdings 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 and net of issuance costs totaled
approximately $99.3 million. Since this issuance occurred after March
31, 2009, its impact is not reflected in the consolidated balance
sheet.
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 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.
Vectren Capital Corp. 2009
Debt Issuance
On March
11, 2009, Vectren and Vectren Capital Corp., its wholly-owned subsidiary
(Vectren Capital), entered into a private placement Note Purchase Agreement (the
“2009 Note Purchase Agreement”) pursuant to which various institutional
investors purchased the following tranches of notes from Vectren Capital: (i)
$30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in
6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30
percent senior notes, Series C due 2019. These senior notes are unconditionally
guaranteed by Vectren, the parent of Vectren Capital. These notes
have no sinking fund requirements, and interest payments are due
semi-annually. The proceeds from the sale of the notes and net of
issuance costs totaled approximately $149.0 million.
The 2009
Note Purchase Agreement contains customary representations, warranties and
covenants, including a leverage covenant consistent with leverage covenants
contained in the Vectren Capital $255 million short-term credit
facility.
On March
11, 2009, Vectren and Vectren Capital also entered into a first amendment with
respect to prior note purchase agreements for the remaining outstanding Vectren
Capital debt, other than the $22.5 million series due in 2010, to conform the
covenants in certain respects to those contained in the 2009 Note Purchase
Agreement.
9.
|
Commitments
& Contingencies
|
Guarantees
In the
normal course of business, Vectren Corporation issues guarantees supporting the
performance of its consolidated subsidiaries as well as its unconsolidated
affiliates. Such guarantees which contain varying terms generally allow
those subsidiaries and affiliates to execute transactions on more favorable
terms than the subsidiaries and affiliates could obtain without such a
guarantee. Guarantees may include posted letters of credit, leasing
guarantees, and contract performance guarantees.
Related
specifically to guarantees supporting the performance and activities of
unconsolidated affiliates, as of March 31, 2009, such guarantees approximated $3
million. These guarantees relate primarily to arrangements between
ProLiance and various natural gas pipeline operators. The Company has
accrued no liabilities for these unconsolidated affiliate guarantees as they
were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others.”
Legal
Proceedings
The
Company is party to various legal proceedings arising in the normal course of
business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position, results of operations or cash
flows.
10.
|
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. Utilization of the Company’s inventory of NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of the these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. It is possible that the vacatur of the CAMR regulations
will lead to increased support for the passage of a multi-pollutant bill in
Congress. It is also possible that the USEPA will promulgate a
revised mercury regulation in 2009.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. Prior to being included in base rates, return
on investments made and recovery of related operating expenses were recovered
through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. Through
March 31, 2009, 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
There are
currently several forms of legislation being circulated at the federal level
addressing the climate change issue. These proposals generally
involve either: 1) a “cap and trade” approach where there is a progressive cap
on greenhouse gas emissions and an auctioning and subsequent trading of
allowances among those that emit greenhouse gases or 2) a carbon
tax. Most proposed legislation also includes a federal renewable
energy portfolio standard. Currently no legislation has passed either
house of Congress. However, The U.S. House of Representatives
is currently debating a comprehensive energy bill proposal that includes a
carbon cap and trade program, a federal renewable portfolio standard, and
utility energy efficiency targets.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in the State
of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas
Reduction Accord, and in the recently completed 2009 session, its legislature
debated, but did not pass, a renewable energy portfolio standard.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from new motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. 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. Upon finalization, the
endangerment finding 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
also proposed a significant new mandatory greenhouse gas emissions
registry.
Impact
of Legislative Actions and Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants,
nonutility coal mining operations, and possibly natural gas distribution
businesses. Further, any legislation would likely impact the Company’s
generation resource planning decisions. At this time and in the absence of
final legislation, compliance costs and other effects associated with reductions
in greenhouse gas emissions or obtaining renewable energy sources remain
uncertain. The Company has gathered preliminary estimates of the costs to
comply with a cap and trade approach to controlling greenhouse gas
emissions. A preliminary investigation demonstrated costs to comply
would be significant, first to operating expenses for the purchase of
allowances, and later to capital expenditures as technology becomes available to
control greenhouse gas emissions. However, these compliance cost
estimates are very sensitive to highly uncertain assumptions, including
allowance prices 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 22
percent of electric volumes sold in 2008 were delivered to municipal and other
wholesale customers. As such, the Company has some flexibility to
modify the level of these transactions to reduce overall emissions and reduce
costs associated with complying with new environmental regulations.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that owned or
operated these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded cumulative costs
that it reasonably expects to incur totaling approximately $22.2
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 received and recorded settlements
from all known insurance carriers under insurance policies in effect when these
plants were in operation in an aggregate amount approximating $20.5
million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has filed a declaratory judgment action against its insurance carriers seeking a
judgment finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit. While the total costs that may be incurred in connection
with addressing these sites cannot be determined at this time, SIGECO has
recorded cumulative costs that it reasonably expects to incur totaling
approximately $9.2 million. With respect to insurance coverage,
SIGECO has received and recorded settlements from insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.1 million.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. While
the Company’s utilities have recorded all costs which they presently expect to
incur in connection with activities at these sites, it is possible that future
events may require some level of additional remedial activities which are not
presently foreseen and those costs may not be subject to PRP or insurance
recovery. As of March 31, 2009 and December 31, 2008, approximately
$6.0 million and $6.5 million, respectively, of accrued, but not yet spent,
remediation costs are included in Other Liabilities related to
both the Indiana Gas and SIGECO sites.
11.
|
Rate
& Regulatory Matters
|
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Order Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also 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 does continue once this base rate increase is in
effect. After year one, nearly 90 percent of the combined residential
and commercial base rate margins will be 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,
and all such requests have been denied.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of bad debt and percent of
income payment plan (PIPP) expenses; base rate recovery of pipeline integrity
management expense; timely recovery of costs associated with the accelerated
replacement of bare steel and cast iron pipes, as well as certain service
risers; and expanded conservation programs now totaling up to $5 million in
annual expenditures.
MISO
Since
2002 and with the IURC’s approval, the Company has been a member of the Midwest
Independent System Operator, Inc. (MISO), a FERC approved regional transmission
organization. The MISO serves the electrical transmission needs of much of
the Midwest and maintains operational control over the Company’s electric
transmission facilities as well as that of other Midwest utilities. Since
April 1, 2005, the Company has been an active participant in the MISO energy
markets, bidding its owned generation into the Day Ahead and Real Time markets
and procuring power for its retail customers at Locational Marginal Pricing
(LMP) as determined by the MISO market.
The
Company is typically in a net sales position with MISO as generation capacity is
in excess of that needed to serve native load and is only occasionally in a net
purchase position. When the Company is a net seller such net revenues are
included in Electric Utility
revenues and when the Company is a net purchaser such net purchases are
included in Cost of fuel and
purchased power. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO day ahead and real-time markets. Net revenues from wholesale
activities included in Electric Utility revenues
totaled $12.9 million and $21.4 million in the three months ended March 31, 2009
and 2008 respectively.
The
Company also receives transmission revenue that results from other members’ use
of the Company’s transmission system. These revenues are also
included in Electric Utility
revenues. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered/refunded through tracking
mechanisms.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM. 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 $2.1 million for the three months March 31,
2009.
Vectren South Electric Lost
Margin Recovery Filing
In 2008,
the Company made an initial filing with the IURC requesting a multi-year program
to promote energy conservation and expanded demand side management programs
within its Vectren South electric utility. As proposed, costs
associated with these programs would be recovered through a tracking
mechanism. The implementation of these programs is designed to work
in tandem with a lost margin recovery mechanism. This mechanism, as
proposed, allows recovery of a portion of rates from residential and commercial
customers based on the level of customer revenues established in Vectren South’s
last electric general rate case. This program is similar to programs
authorized by the IURC in the Company’s Indiana natural gas service
territories. In April of 2009, all filings were completed, and the
Company would expect an IURC decision to occur during 2009.
Adoption of SFAS
161
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS
161). SFAS 161 describes enhanced disclosures under SFAS 133 and
requires that objectives for using derivative instruments be disclosed in terms
of underlying risk and accounting designation in order to better convey the
purpose of derivative use in terms of the risks that the entity is intending to
manage. The Company adopted the qualitative and quantitative
disclosures required in both interim and annual financial statements described
in SFAS 161 on January 1, 2009.
Accounting Policy for
Derivatives
The
Company occasionally executes derivative contracts in the normal course of
operations while buying and selling commodities to be used in operations,
optimizing its generation assets, and managing risk. The Company
accounts for its derivative contracts in accordance with SFAS 133, “Accounting
for Derivatives” and its related amendments and interpretations. In
most cases, SFAS 133 requires a derivative to be recorded on the balance sheet
as an asset or liability measured at its market value and that a change in the
derivative's market value be recognized currently in earnings unless specific
hedge criteria are met.
When an
energy contract that is a derivative is designated and documented as a normal
purchase or normal sale (NPNS), it is exempted from mark-to-market
accounting. Most energy contracts executed by the Company are subject
to the NPNS exclusion. Such energy contracts include real time and
day ahead purchase and sale contracts with the MISO, natural gas purchases from
ProLiance and others, and wind farm and other electric generating capacity
contracts.
When the
Company engages in energy contracts and financial contracts that are derivatives
and are not subject to the NPNS or other exclusions identified in SFAS 133, such
contracts are recorded at market value as current or noncurrent assets or
liabilities depending on their value and on when the contracts are expected to
be settled. Contracts and any associated collateral with
counter-parties subject to master netting arrangements are presented net in the
Consolidated Balance Sheets. The offset resulting from carrying the
derivative at fair value on the balance sheet is charged to earnings unless it
qualifies as a hedge or is subject to SFAS 71. When hedge accounting
is appropriate, the Company assesses and documents hedging relationships between
the derivative contract and underlying risks as well as its risk management
objectives and anticipated effectiveness. When the hedging
relationship is highly effective, derivatives are designated as
hedges. The market value of the effective portion of the hedge is
marked to market in accumulated other comprehensive income for cash flow
hedges. Ineffective portions of hedging arrangements are
marked-to-market through earnings. For fair value hedges, both the
derivative and the underlying hedged item are marked to market through
earnings. The offset to contracts affected by SFAS 71 are
marked-to-market as a regulatory asset or liability. Market value for
derivative contracts is determined using quoted market prices from independent
sources. The Company rarely enters into contracts where internal
models are used calculate fair values that impact the financial
statements.
Derivative Use in Risk
Mitigation Strategies
Following
is a more detailed discussion of activities where the Company may use
derivatives to mitigate risk.
Emission
Allowance Risk Management
The
Company’s wholesale power marketing operations are exposed to price risk
associated with emission allowances. To mitigate this risk, the
Company executed call options to hedge wholesale SO2 emission
allowance utilization in future periods. The Company designated and
documented these derivatives as cash flow hedges. At March 31, 2009,
a deferred gain of approximately $0.1 million remains in accumulated
comprehensive income related to these call options which will be recognized in
earnings as emission allowances are utilized. As of and for the
periods reported in these financial statements, ending values and activity
relating to emission allowance derivatives affecting the statements of income
and cash flows were not significant.
Natural
Gas Procurement Risk Management
The
Company’s regulated operations have limited exposure to commodity price risk for
purchases and sales of natural gas and electricity for retail customers due to
current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment and other mechanisms. Although regulated operations
are exposed to limited commodity price risk, volatile natural gas prices can
still have negative economic impacts, including higher interest
costs. The Company may mitigate these economic risks by using
derivative contracts. These contracts are subject to regulation which
allows for reasonable and prudent hedging costs to be recovered through
rates. When regulation is involved, SFAS 71 controls when the offset
to mark-to-market accounting is recognized in earnings.
The
Company’s wholly owned gas retail operations also mitigate price risk associated
with forecasted natural gas purchases by using derivatives. These
nonregulated gas retail operations may also from time-to-time execute weather
derivatives to mitigate extreme weather affecting unregulated gas retail
sales.
As of and
for the periods reported in these financial statements, ending values and
activity relating to natural gas procurement derivatives affecting the
statements of income and cash flows were not significant.
Interest
Rate Risk Management
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on interest
expense. The Company has used interest rate swaps and treasury locks
to hedge forecasted debt issuances and other interest rate swaps to manage
interest rate exposure.
As of
March 31, 2009 and December 31, 2008, no interest rate swaps were
outstanding. Related to derivative instruments associated with
completed debts issuances, an approximate $7.8 million net regulatory asset
remains at March 31, 2009. In the three months ended March 31, 2009 and 2008,
$0.1 million was reclassified as a decrease to interest expense. The
Company estimates a $0.3 million reduction to interest expense will occur in
2009 related to the amortization of this net position.
Credit
Features
Master
agreements in place with certain counterparties contain provisions involving the
Company’s credit ratings. If ratings were to fall below investment grade,
counterparties to these arrangements could request immediate payment or demand
immediate and ongoing full overnight collateralization on net liability
positions. Currently, contracts to purchase natural gas by the Company’s
nonutility retail gas marketer to fulfill its retail sales are the only
significant derivative-like instruments impacted by credit contingent
features. Such contracts are subject to the NPNS
exclusion. Generally, the natural gas supply period supported by
these arrangements is 60 days, but in some instances, may include forecasted
purchases up to 12 months in advance. If the credit-risk-related
contingent features underlying these agreements were triggered, the Company
would be required to post approximately $5 million of additional collateral at
March 31, 2009.
13.
|
Fair
Value Measurements
|
Financial
assets and liabilities and certain nonfinancial assets and liabilities that are
revalued at fair value on a recurring basis are valued and disclosed in
accordance with SFAS No. 157, “Fair Value Measurements” (SFAS
157). SFAS 157 defines a hierarchy for disclosing fair value
measurements based primarily on the level of public data used in determining
fair value. Level 1 inputs include quoted market prices in active markets
for identical assets or liabilities; Level 2 inputs include inputs other than
Level 1 inputs that are directly or indirectly observable; and Level 3 inputs
include unobservable inputs using estimates and assumptions developed using
internal models, which reflect what a market participant would use to determine
fair value. For the balance sheet dates presented in these financial
statements, other than $75 million invested in money market funds and included
in Cash and cash equivalents
as of December 31, 2008, the Company had no material assets or
liabilities recorded at fair value outstanding, and none outstanding valued
using Level 3 inputs. The money market investments were valued using
Level 1 inputs, and none were outstanding at March 31, 2009.
On January 1, 2009, the Company adopted
the provisions of SFAS 157 as they relate to nonfinancial assets and
nonfinancial liabilities that are measured at fair value on a nonrecurring
basis, such as the initial measurement of an asset retirement obligation or the
use of fair value goodwill, intangible assets and long-lived assets impairment
tests. This adoption had no significant impact on the Company’s
operating results or financial condition.
14.
|
Impact
of Other Newly Adopted and Newly Issued Accounting
Principles
|
SFAS
141R
On
January 1, 2009, the Company adopted SFAS No. 141, “Business Combinations” (SFAS
141R). SFAS 141R establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141R applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. Because the provisions of this
standard are applied prospectively, the impact to the Company cannot be
determined until the transactions occur.
SFAS 160
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS
160). SFAS 160 establishes accounting and reporting standards that
require ownership percentages in material subsidiaries held by parties other
than the parent be clearly identified, labeled, and presented separately from
the parent’s equity in the equity section of the consolidated balance sheet; the
amount of consolidated net income attributable to the parent and the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement; that changes in the parent’s ownership
interest while it retains control over its subsidiary be accounted for
consistently; that when a subsidiary is deconsolidated, any retained
noncontrolling equity investment be initially measured at fair value; and that
sufficient disclosure is made to clearly identify and distinguish between the
interests of the parent and the noncontrolling owners. The adoption
of SFAS 160 on January 1, 2009 had an immaterial impact to the Company’s
presentation of its financial position and operating results.
EITF
08-05
On
January 1, 2009, the Company adopted EITF Issue No. 08-5, “Issuer's Accounting
for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”
(EITF 08-5). EITF 08-5 states that companies should not include the
effect of third-party credit enhancements in the fair value measurement of the
related liabilities. EITF 08-5 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
March 31, 2009, the Company has approximately $251.1 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. It is not anticipated, the
Company’s valuation techniques will change materially at a result of the
adoption of EITF 08-5.
FASB Staff Position (FSP)
142-3
FASB Staff Positions on Fair
Value Accounting and Disclosure
In April
2009 the FASB released FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures
about Fair Value of Financial Instruments” (FSP 107-1) to require an entity to
disclose in the body or in the accompanying notes of its summarized financial
information for interim reporting periods and in its financial statements for
annual reporting periods the fair value of all financial instruments for which
it is practicable to estimate that value, whether recognized or not recognized
in the statement of financial position, as required by FASB Statement No.
107. FSP 107-1 is effective for interim reporting periods ending
after June 15, 2009, with early adoption permitted for periods ending after
March 15, 2009. FSP 107-1 does not require disclosures for earlier
periods presented for comparative purposes at initial adoption. In
periods after initial adoption, FSP 107-1 requires comparative disclosures only
for periods ending after initial adoption.
An entity
may early adopt FSP 107-1 only if it also elects to early adopt FSP FAS 157-4,
“Determining Fair Value When the Volume and Level of
Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly which provides additional guidance for
estimating fair value in accordance with FASB Statement No. 157 when the volume
and level of activity for the asset or liability have significantly decreased
and also includes guidance on identifying circumstances that indicate a
transaction is not orderly and FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of
Other-Than-Temporary Impairments” which impacts the impairment testing of
debt securities held for investment purposes and the presentation and disclosure
requirements for debt and equity securities described in FASB Statement
115.
The
Company will adopt these FSP’s for its 2009 second quarter
reporting. It is not expected the impact of adoption will be material
to its cash flows, operations, or financial condition, but will impact interim
period fair value disclosures.
FSP No. FAS
132(R)-1
In
December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about
Postretirement Benefit Plan Assets” (FSP 132(R)-1). FSP
132(R)-1 amends the plan asset disclosures required under FAS Statement No.
132(R) to provide guidance on an employer’s disclosures about plan assets of a
defined benefit pension or other postretirement plan. Guidance provided by this
FSP relates to disclosures about investment policies and strategies, categories
of plan assets, fair value measurements of plan assets, and significant
concentrations of risk. FSP FAS 132(R)-1 is effective for fiscal years
ending after December 15, 2009. The Company will include FSP FAS 132(R)-1’s
disclosure requirements in its 2009 annual financial statements.
The
Company segregates its operations into three groups: 1) Utility Group, 2)
Nonutility Group, and 3) Corporate and Other.
The
Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which
consist of the Company’s regulated operations and other operations that provide
information technology and other support services to those regulated
operations. The Company segregates its regulated operations into a
Gas Utility Services operating segment and an Electric Utility Services
operating segment. The Gas Utility Services segment provides natural
gas distribution and transportation services to nearly two-thirds of Indiana and
to west central Ohio. The Electric Utility Services segment provides
electric distribution services primarily to southwestern Indiana, and includes
the Company’s power generating and wholesale power operations. The
Company manages its regulated operations as separated between Energy Delivery,
which includes the gas and electric transmission and distribution functions, and
Power Supply, which includes the power generating and wholesale power
operations. In total, regulated operations supply natural gas and /or
electricity to over one million customers.
The
Nonutility Group is comprised of one operating segment that includes various
subsidiaries and affiliates investing in energy marketing and services, coal
mining, and energy infrastructure services, among other energy-related
opportunities.
Corporate
and Other includes unallocated corporate expenses such as advertising and
charitable contributions, among other activities, that benefit the Company’s
other operating segments. Net income is the measure of profitability
used by management for all operations.
Information
related to the Company’s business segments is summarized below:
|
|
Three
Months Ended March 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
Revenues
|
|
|
|
|
|
|
Utility
Group
|
|
|
|
|
|
|
Gas
Utility Services
|
|
$ |
527.4 |
|
|
$ |
633.6 |
|
Electric
Utility Services
|
|
|
125.0 |
|
|
|
127.2 |
|
Other
Operations
|
|
|
10.7 |
|
|
|
11.7 |
|
Eliminations
|
|
|
(10.3 |
) |
|
|
(11.1 |
) |
Total
Utility Group
|
|
|
652.8 |
|
|
|
761.4 |
|
Nonutility
Group
|
|
|
191.2 |
|
|
|
169.7 |
|
Eliminations
|
|
|
(48.8 |
) |
|
|
(29.0 |
) |
Consolidated
Revenues
|
|
$ |
795.2 |
|
|
$ |
902.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profitability
Measure - Net Income
|
|
|
|
|
|
|
|
|
Gas
Utility Services
|
|
$ |
41.2 |
|
|
$ |
42.3 |
|
Electric
Utility Services
|
|
|
11.9 |
|
|
|
12.6 |
|
Other
Operations
|
|
|
3.1 |
|
|
|
3.1 |
|
Utility
Group Net Income
|
|
|
56.2 |
|
|
|
58.0 |
|
Nonutility
Group Net Income
|
|
|
16.5 |
|
|
|
6.3 |
|
Corporate
& Other Group Net Income
|
|
|
0.1 |
|
|
|
(0.3 |
) |
Consolidated
Net Income
|
|
$ |
72.8 |
|
|
$ |
64.0 |
|
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Description of the
Business
Vectren
Corporation (the Company or Vectren), an Indiana corporation, is an energy
holding company headquartered in Evansville, Indiana. The Company’s
wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings),
serves as the intermediate holding company for three 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. Utility Holdings’ consolidated operations are collectively
referred to as the Utility Group. Both Vectren and Utility Holdings
are holding companies as defined by the Energy Policy Act of 2005 (Energy
Act). Vectren was incorporated under the laws of Indiana on June 10,
1999.
Indiana
Gas provides energy delivery services to over 567,000 natural gas customers
located in central and southern Indiana. SIGECO provides energy
delivery services to over 141,000 electric customers and approximately 111,000
gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and
SIGECO generally do business as Vectren Energy Delivery of
Indiana. The Ohio operations provide energy delivery services to
approximately 317,000 natural gas customers located near Dayton in west central
Ohio. The Ohio operations are owned as a tenancy in common by Vectren
Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility
Holdings (53 percent ownership), and Indiana Gas (47 percent
ownership). The Ohio operations generally do business as Vectren
Energy Delivery of Ohio.
The
Company, through Vectren Enterprises, Inc. (Enterprises), is involved in
nonutility activities in three primary business areas: Energy
Marketing and Services, Coal Mining and Energy Infrastructure
Services. Energy Marketing and Services markets and supplies natural
gas and provides energy management services. Coal Mining mines and
sells coal. Energy Infrastructure Services provides underground
construction and repair services and performance contracting and renewable
energy services. Enterprises also has other legacy businesses that
have invested in energy-related opportunities and services, real estate, and
leveraged leases, among other investments. These operations are
collectively referred to as the Nonutility Group. Enterprises
supports the Company’s regulated utilities pursuant to service contracts by
providing natural gas supply services, coal, and infrastructure
services.
In this
discussion and analysis, the Company analyzes contributions to consolidated
earnings and earnings per share from its Utility Group and Nonutility Group
separately since each operates independently requiring distinct competencies and
business strategies, offers different energy and energy related products and
services, and experiences different opportunities and
risks. Nonutility Group operations are discussed below as primary
operations and other operations. Primary nonutility operations denote
areas of management’s forward looking focus.
Per
share earnings contributions of the Utility Group, Nonutility Group, and
Corporate and Other are presented. Such per share amounts are based
on the earnings contribution of each group included in Vectren’s
consolidated results divided by Vectren’s basic average shares outstanding
during the period. The earnings per share of the groups do not
represent a direct legal interest in the assets and liabilities allocated
to the groups, but rather represent a direct equity interest in Vectren
Corporation's assets and liabilities as a whole. These non-gaap
measures are used by management to evaluate the performance of individual
businesses. Accordingly management believes these measures are
useful to investors in understanding each business’ contribution to
consolidated earnings per share and analyzing period to period
changes.
|
The
Utility Group generates revenue primarily from the delivery of natural gas and
electric service to its customers. The primary source of cash flow for the
Utility Group results from the collection of customer bills and the payment for
goods and services procured for the delivery of gas and electric services.
The activities of and revenues and cash flows generated by the Nonutility Group
are closely linked to the utility industry, and the results of those operations
are generally impacted by factors similar to those impacting the overall utility
industry. In addition, there are other operations, referred to herein
as Corporate and Other, that include unallocated corporate expenses such as
advertising and charitable contributions, among other activities.
The
Company has in place a disclosure committee that consists of senior management
as well as financial management. The committee is actively involved
in the preparation and review of the Company’s SEC filings.
Executive Summary of
Consolidated Results of Operations
The
following discussion and analysis should be read in conjunction with the
unaudited condensed consolidated financial statements and notes thereto as
well as the Company’s 2008 annual report filed on Form
10-K.
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
(In
millions, except per share data)
|
|
2009
|
|
|
2008
|
|
Net
income
|
|
|
$ |
72.8 |
|
|
$ |
64.0 |
|
Attributed
to:
|
Utility
Group
|
|
|
56.2 |
|
|
|
58.0 |
|
|
Nonutility
Group
|
|
|
16.5 |
|
|
|
6.3 |
|
|
Corporate
& other
|
|
|
0.1 |
|
|
|
(0.3 |
) |
Basic
earnings per share
|
|
$ |
0.90 |
|
|
$ |
0.84 |
|
Attributed
to:
|
Utility
Group
|
|
|
0.70 |
|
|
|
0.76 |
|
Nonutility Group
|
|
|
0.20 |
|
|
|
0.08 |
|
Corporate & other
|
|
|
- |
|
|
|
- |
|
Results
For
the three months ended March 31, 2009, net income was $72.8 million, or $0.90
per share, compared to $64.0 million, or $0.84 per share for the three months
ended March 31, 2008. Year over year increases in primary nonutility
operations offset lower Utility Group results. Earnings per share are
$0.04 per share lower due to the increased number of common shares outstanding
as a result of the issuance of common shares in June 2008.
Utility
Group
In
2009, the Utility Group’s earnings were $56.2 million compared to $58.0 million
in 2008, a decrease of $1.8 million. The decrease resulted primarily
from lower customer usage and from wholesale power sales, both of which have
been impacted by the recession. Increased revenues associated with
regulatory initiatives and lower interest costs partially offset these
declines.
Nonutility
Group
The
Nonutility Group’s 2009 first quarter earnings were $16.5 million compared to
$6.3 million in 2008. The increase is due to earnings from the
primary nonutility operations. The Company’s primary nonutility
operations contributed $17.7 million in the first quarter of 2009, compared to
$4.9 million in the first quarter of 2008. Primary nonutility
operations are Energy Marketing and Services companies, Coal Mining operations,
and Energy Infrastructure Services companies.
Of
the $12.8 million increase in primary nonutility group earnings, $6.4 million is
attributable to Energy Marketing and Services and $3.7 million is attributable
to Coal Mining. The increase in Energy Marketing and Services’
earnings primarily results from increased retail gas marketing
earnings. Coal Mining earnings have increased as expected as
contracts reflecting the higher Illinois Basin coal market prices began on
January 1st. Seasonal
losses associated with Energy Infrastructure Services narrowed approximately
$2.7 million quarter over quarter to $0.5 million.
Dividends
Dividends
declared for the three months ended March 31, 2009, were $0.335 per share
compared to $0.325 per share for the same period in 2008.
Detailed
Discussion of Results of Operations
Following
is a more detailed discussion of the results of operations of the Company’s
Utility and Nonutility operations. The detailed results of operations
for these operations are presented and analyzed before the reclassification and
elimination of certain intersegment transactions necessary to consolidate those
results into the Company’s Consolidated Statements of Income.
Results of Operations of the
Utility Group
The
Utility Group is comprised of Utility Holdings’ operations. The
operations of the Utility Group consist of the Company’s regulated operations
and other operations that provide information technology and other support
services to those regulated operations. Regulated operations consist
of a natural gas distribution business that provides natural gas distribution
and transportation services to nearly two-thirds of Indiana and to west central
Ohio and an electric transmission and distribution business, which provides
electric distribution services primarily to southwestern Indiana, and the
Company’s power generating and wholesale power operations. In total,
these regulated operations supply natural gas and/or electricity to over one
million customers. Utility Group operating results before certain
intersegment eliminations and reclassifications for the three months ended March
31, 2009 and 2008 follow:
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31,
|
|
(In
millions, except per share data)
|
|
2009
|
|
|
2008
|
|
OPERATING
REVENUES
|
|
|
|
|
|
|
Gas
utility
|
|
$ |
527.4 |
|
|
$ |
633.6 |
|
Electric
utility
|
|
|
125.0 |
|
|
|
127.2 |
|
Other
|
|
|
0.4 |
|
|
|
0.6 |
|
Total
operating revenues
|
|
|
652.8 |
|
|
|
761.4 |
|
OPERATING
EXPENSES
|
|
|
|
|
|
|
|
|
Cost
of gas sold
|
|
|
354.6 |
|
|
|
462.0 |
|
Cost
of fuel & purchased power
|
|
|
47.0 |
|
|
|
46.0 |
|
Other
operating
|
|
|
79.3 |
|
|
|
74.0 |
|
Depreciation
& amortization
|
|
|
43.9 |
|
|
|
40.7 |
|
Taxes
other than income taxes
|
|
|
22.8 |
|
|
|
26.2 |
|
Total
operating expenses
|
|
|
547.6 |
|
|
|
648.9 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
105.2 |
|
|
|
112.5 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME - NET
|
|
|
1.5 |
|
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
INTEREST
EXPENSE
|
|
|
18.7 |
|
|
|
20.8 |
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
88.0 |
|
|
|
93.7 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
31.8 |
|
|
|
35.7 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
56.2 |
|
|
$ |
58.0 |
|
|
|
|
|
|
|
|
|
|
CONTRIBUTION
TO VECTREN BASIC EPS
|
|
$ |
0.70 |
|
|
$ |
0.76 |
|
Significant
Fluctuations
Utility
Group Margin
Throughout
this discussion, the terms Gas Utility margin and Electric Utility margin are
used. Gas Utility margin is calculated as Gas utility
revenues less the Cost of
gas. Electric Utility margin is calculated as Electric
utility revenues less Cost of fuel
& purchased power. The Company believes Gas Utility and
Electric Utility margins are better indicators of relative contribution than
revenues since gas prices and fuel costs can be volatile and are generally
collected on a dollar-for-dollar basis from customers.
Sales
of natural gas and electricity to residential and commercial customers are
seasonal and are impacted by weather. Trends in average use among natural
gas residential and commercial customers have tended to decline in recent years
as more efficient appliances and furnaces are installed and the price of natural
gas have 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 service charge revenues and less dependent on
volumetric revenues than previous rate designs. This new rate design, which will
be fully phased in February 2010, will eventually mitigate most weather risk in
Ohio. SIGECO’s electric service territory has neither NTA nor lost
margin recovery mechanisms.
Gas
and electric margin generated from sales to large customers (generally
industrial and other contract customers) is primarily impacted by overall
economic conditions and changes in demand for those customers’
products. The recent recession has had and may continue to have some
negative impact on both gas and electric large customers. This impact
has included, and may continue to include, tempered growth, significant
conservation measures, and perhaps even plant closures or
bankruptcies. While no one industrial customer comprises 10 percent
of consolidated margin, the top five industrial electric customers comprise
approximately 11 percent of electric utility margin in the three months ended
March 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.
Margin
is also impacted by the collection of state mandated taxes, which fluctuate with
gas and fuel costs, as well as other tracked expenses. Expenses
subject to tracking mechanisms include Ohio bad debts and percent of income
payment plan expenses, costs associated with exiting the merchant function and
to perform 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 bad debt 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 and regional transmission investments are also
tracked.
Electric
wholesale activities are primarily affected by market conditions, the level of
excess generating capacity, and electric transmission availability.
Following is a discussion and analysis of margin generated from regulated
utility operations.
Gas
Utility Margin (Gas utility revenues less Cost of gas)
Gas
Utility margin and throughput by customer type follows:
|
|
Three
Months Ended March 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
Gas
utility revenues
|
|
$ |
527.4 |
|
|
$ |
633.6 |
|
Cost
of gas sold
|
|
|
354.6 |
|
|
|
462.0 |
|
Total gas
utility margin
|
|
$ |
172.8 |
|
|
$ |
171.6 |
|
Margin
attributed to:
|
|
|
|
|
|
|
|
|
Residential
& commercial customers
|
|
$ |
152.6 |
|
|
$ |
150.9 |
|
Industrial
customers
|
|
|
15.1 |
|
|
|
16.5 |
|
Other
|
|
|
5.1 |
|
|
|
4.2 |
|
Sold
& transported volumes in MMDth attributed to:
|
|
|
|
|
|
Residential
& commercial customers
|
|
|
52.6 |
|
|
|
57.8 |
|
Industrial
customers
|
|
|
24.1 |
|
|
|
28.7 |
|
Total sold & transported volumes
|
|
|
76.7 |
|
|
|
86.5 |
|
For the
quarter ended March 31, 2009, gas utility margins were $172.8 million,
increasing $1.2 million over the prior year. Margin increases
associated with regulatory initiatives including the full impact of the Vectren
North base rate increase effective in February 14, 2008 and the Vectren Ohio
base rate increase effective February 22, 2009, were $3.5
million. Increases were offset by impacts of the recession, including
an estimated $1.9 million decrease in industrial customer margin and slightly
lower residential and commercial customer counts, which decreased margin
approximately $0.6 million. The impact of operating costs, including
revenue and usage taxes, recovered in margin was generally flat year over year
and reflects lower revenue taxes offset by higher pass through operating
expenses. The average cost per dekatherm of gas purchased for the
three months ended March 31, 2009, was $7.39 compared to $9.44 in
2008.
Electric
Utility Margin (Electric Utility revenues less Cost of fuel and purchased
power)
Electric
Utility margin and volumes sold by customer type follows:
|
|
Three
Months Ended March 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
Electric
utility revenues
|
|
$ |
125.0 |
|
|
$ |
127.2 |
|
Cost
of fuel & purchased power
|
|
|
47.0 |
|
|
|
46.0 |
|
Total
electric utility margin
|
|
$ |
78.0 |
|
|
$ |
81.2 |
|
Margin
attributed to:
|
|
|
|
|
|
|
|
|
Residential
& commercial customers
|
|
$ |
52.5 |
|
|
$ |
51.3 |
|
Industrial
customers
|
|
|
19.1 |
|
|
|
20.2 |
|
Other
customers
|
|
|
0.7 |
|
|
|
1.6 |
|
Subtotal:
retail & firm wholesale
|
|
$ |
72.3 |
|
|
$ |
73.1 |
|
Wholesale
power marketing
|
|
$ |
5.7 |
|
|
$ |
8.1 |
|
|
|
|
|
|
|
|
|
|
Electric
volumes sold in GWh attributed to:
|
|
|
|
|
|
|
|
|
Residential
& commercial customers
|
|
|
671.6 |
|
|
|
715.2 |
|
Industrial
customers
|
|
|
509.0 |
|
|
|
600.7 |
|
Other
customers
|
|
|
5.1 |
|
|
|
36.6 |
|
Total
retail & firm wholesale volumes sold
|
|
|
1,185.7 |
|
|
|
1,352.5 |
|
Retail
Margin
Electric
retail and firm wholesale utility margins were $72.3 million for the three
months ended March 31, 2009, a decrease over the prior year of $0.8
million. Increased margin associated with returns on pollution
control investments totaled $0.5 million; margin associated with tracked costs
such as recovery of pollution control and MISO operating expenses increased $2.6
million. Management estimates other usage declines associated with
the weak economy to have decreased margin approximately $1.4 million for
residential and commercial customers and $2.0 million for industrial
customers.
Margin
from Wholesale Activities
Periodically,
generation capacity is in excess of native load. The Company markets
and sells this unutilized generating and transmission capacity to optimize the
return on its owned assets. A majority of the margin generated from
these activities is associated with wholesale off-system sales, and
substantially all off-system sales occur into the MISO Day Ahead and Real Time
markets.
Further
detail of Wholesale
activity follows:
|
|
Three
months ended March 31,
|
|
(In
millions)
|
|
2009
|
|
|
2008
|
|
Off-system
sales
|
|
$ |
2.7 |
|
|
$ |
7.2 |
|
Transmission
system sales
|
|
|
3.0 |
|
|
|
0.9 |
|
Total
wholesale power marketing
|
|
$ |
5.7 |
|
|
$ |
8.1 |
|
For the
quarter ended March 31, 2009, total wholesale margins were $5.7 million,
representing a decrease of $2.4 million, compared to 2008.
During
2009, margin from off-system sales retained by the Company decreased $4.5
million compared to 2008. The Company experienced lower wholesale
power marketing margins due to lower wholesale prices, coupled with increasing
coal costs. Off-system sales totaled 341.6 GWh in 2009, compared to
463.4 GWh in 2008. The base rate case effective August 17, 2007,
requires that wholesale margin from off-system sales earned above or below $10.5
million be shared equally with customers as measured on a fiscal year ending in
August, and results 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 benefit
reliability throughout the region. Margin associated with these
projects totaled $2.1 million in 2009.
Utility Group Operating
Expenses
Other
Operating Expenses
For the
three months ended March 31, 2009, other operating expenses were $79.3 million,
an increase of $5.3 million, compared to 2008. Substantially all of
the increase results from increased costs directly recovered through utility
margin. Examples of such tracked costs include Ohio bad debts,
Indiana gas pipeline integrity management costs, costs to fund Indiana energy
efficiency programs, and MISO transmission revenues and costs, among
others. Other operating costs were generally flat.
Depreciation
& Amortization
Depreciation
expense was $43.9 million for the quarter, an increase of $3.2 million compared
to 2008. Plant additions include the approximate $100 million SO2 scrubber
placed into service January 1, 2009 for which depreciation totaling $1.1 million
is directly recovered in electric utility margin.
Taxes
Other Than Income Taxes
Taxes
other than income taxes were $22.8 million for the quarter, a decrease of $3.4
million compared to the prior year quarter. The decrease is
attributable to lower utility receipts, excise, and usage taxes caused
principally by lower gas prices and is tracked in revenues.
Other
Income-Net
Other-net reflects income of $1.5
million for the quarter, a decrease of $0.5 million compared to the prior year
quarter. The decrease is primarily attributable to lower
capitalization of funds used during construction as a result of lower borrowing
costs.
Interest
Expense
Interest
expense was $18.7 million for the quarter, a decrease of $2.1 million compared
to the prior year quarter. The decrease reflects lower short-term
interest rates and lower average short-term debt balances.
Income
Taxes
In 2009,
federal and state income taxes were $31.8 million for the quarter, a decrease of
$3.9 million compared to the prior year quarter. The lower taxes are
primarily due to lower pretax income.
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. Utilization of the Company’s inventory of NOx and SO2 allowances
may also be impacted if CAIR is further revised; however, most of the these
allowances were granted to the Company at zero cost, so a reduction in carrying
value is not expected.
Similarly,
in March of 2005, USEPA promulgated the Clean Air Mercury Rule
(CAMR). CAMR is an allowance cap and trade program requiring further
reductions in mercury emissions from coal-burning power plants. The
CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in
July 2008. It is possible that the vacatur of the CAMR regulations
will lead to increased support for the passage of a multi-pollutant bill in
Congress. It is also possible that the USEPA will promulgate a
revised mercury regulation in 2009.
To comply
with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR
regulations, and to comply with potential future regulations of mercury and
further NOx and SO2 reductions,
SIGECO has IURC authority to invest in clean coal technology. Using this
authorization, SIGECO has invested approximately $307 million in pollution
control equipment, including Selective Catalytic Reduction (SCR) systems and
fabric filters. SCR technology is the most effective method of
reducing NOx emissions where high removal efficiencies are required and fabric
filters control particulate matter emissions. These investments were
included in rate base for purposes of determining new base rates that went into
effect on August 15, 2007. Prior to being included in base rates, return
on investments made and recovery of related operating expenses were recovered
through a rider mechanism.
Further,
the IURC granted SIGECO authority to invest in an SO2 scrubber
at its generating facility that is jointly owned with ALCOA (the Company’s
portion is 150 MW). The
order allows SIGECO to recover an approximate 8 percent return on capital
investments through a rider mechanism which is periodically updated for actual
costs incurred less post in-service depreciation expense. Through
March 31, 2009, 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
Vectren
is committed to responsible environmental stewardship and conservation efforts
as demonstrated by its proactive approach to balancing environmental and
customer needs. While scientific uncertainties exist and the debate surrounding
global climate change is ongoing, the growing understanding of the science of
climate change would suggest a strong potential for adverse economic and social
consequences should world-wide carbon dioxide (CO2) and other
greenhouse gas emissions continue at present levels.
The need
to reduce CO2 and other
greenhouse gas emissions, yet provide affordable energy requires thoughtful
balance. For these reasons, 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; and
|
·
|
A
strategy supporting alternative energy technologies and biofuels and
increasing the domestic supply of natural gas to reduce dependence on
foreign oil and imported natural
gas.
|
Current
Initiatives to Increase Conservation and Reduce Emissions
The
Company is committed to its policy on climate change and conservation. Evidence
of this commitment includes:
·
|
Focusing
the Company’s mission statement and purpose on corporate sustainability
and the need to help customers conserve and manage energy
costs;
|
·
|
Recently
executing long-term contracts to purchase 80MW of wind energy generated by
wind farms in Benton County,
Indiana;
|
·
|
Evaluating
other renewable energy projects to complement base load coal fired
generation in advance of mandated renewable energy portfolio
standards;
|
·
|
Implementing
conservation initiatives in the Company’s Indiana and Ohio gas utility
service territories;
|
·
|
Participation
in an electric conservation and demand side management collaborative with
the OUCC and other customer advocate
groups;
|
·
|
Evaluating
potential carbon requirements with regard to new generation, other fuel
supply sources, and future environmental compliance
plans;
|
·
|
Reducing
the Company’s carbon footprint by measures such as purchasing hybrid
vehicles, and optimizing generation
efficiencies;
|
·
|
Developing
renewable energy and energy efficiency performance contracting projects
through its wholly owned subsidiary, Energy Systems
Group.
|
Legislative
Actions and Other Climate Change Initiatives
There are
currently several forms of legislation being circulated at the federal level
addressing the climate change issue. These proposals generally
involve either: 1) a “cap and trade” approach where there is a progressive cap
on greenhouse gas emissions and an auctioning and subsequent trading of
allowances among those that emit greenhouse gases or 2) a carbon
tax. Most proposed legislation also includes a federal renewable
energy portfolio standard. Currently no legislation has passed either
house of Congress. However, The U.S. House of Representatives
is currently debating a comprehensive energy bill proposal that includes a
carbon cap and trade program, a federal renewable portfolio standard, and
utility energy efficiency targets.
In the
absence of federal legislation, several regional initiatives throughout the
United States are in the process of establishing regional cap and trade
programs. While no climate change legislation is pending in the State
of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas
Reduction Accord, and in the recently completed 2009 session, its legislature
debated, but did not pass, a renewable energy portfolio standard.
In April
of 2007, the US Supreme Court determined that greenhouse gases meet the
definition of "air pollutant" under the Clean Air Act and ordered the USEPA to
determine whether greenhouse gas emissions from new motor vehicles cause or
contribute to air pollution that may reasonably be anticipated to endanger
public health or welfare. 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. Upon finalization, the
endangerment finding 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
also proposed a significant new mandatory greenhouse gas emissions
registry.
Impact
of Legislative Actions and Other Initiatives is Unknown
If
legislation requiring reductions in CO2 and other
greenhouse gases or legislation mandating a renewable energy portfolio standard
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel generating plants,
nonutility coal mining operations, and possibly natural gas distribution
businesses. Further, any legislation would likely impact the Company’s
generation resource planning decisions. At this time and in the absence of
final legislation, compliance costs and other effects associated with reductions
in greenhouse gas emissions or obtaining renewable energy sources remain
uncertain. The Company has gathered preliminary estimates of the costs to
comply with a cap and trade approach to controlling greenhouse gas
emissions. A preliminary investigation demonstrated costs to comply
would be significant, first to operating expenses for the purchase of allowances
and energy efficiency targets, and later to capital expenditures as technology
becomes available to control greenhouse gas emissions. However, these
compliance cost estimates are very sensitive to highly uncertain assumptions,
including allowance prices. Costs to purchase allowances that cap
greenhouse gas emissions should be considered a cost of providing electricity,
and as such, the Company believes recovery should be timely reflected in rates
charged to customers. Approximately 22 percent of electric volumes
sold in 2008 were delivered to municipal and other wholesale
customers. As such, the Company has some flexibility to modify the
level of these transactions to reduce overall emissions and reduce costs
associated with complying with new environmental regulations.
Environmental Remediation
Efforts
In the
past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines,
these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, those that owned or
operated these facilities may now be required to take remedial action if certain
contaminants are found above the regulatory thresholds at these
sites.
Indiana
Gas identified the existence, location, and certain general characteristics of
26 gas manufacturing and storage sites for which it may have some remedial
responsibility. Indiana Gas completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Indiana Gas submitted the remainder of the
sites to the IDEM's Voluntary Remediation Program (VRP) and is
currently conducting some level of remedial activities, including groundwater
monitoring at certain sites, where deemed appropriate, and will continue
remedial activities at the sites as appropriate and necessary.
Indiana
Gas accrued the estimated costs for further investigation, remediation,
groundwater monitoring, and related costs for the sites. While the
total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, Indiana Gas has recorded cumulative costs
that it reasonably expects to incur totaling approximately $22.2
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 received and recorded settlements
from all known insurance carriers under insurance policies in effect when these
plants were in operation in an aggregate amount approximating $20.5
million.
In
October 2002, SIGECO received a formal information request letter from the IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed
applications to enter four of the manufactured gas plant sites in IDEM's
VRP. The remaining site is currently being addressed in the VRP by
another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal
was approved by the IDEM in February 2004. SIGECO is also named in a
lawsuit filed in federal district court in May 2007, involving another site
subject to potential environmental remediation efforts.
SIGECO
has filed a declaratory judgment action against its insurance carriers seeking a
judgment finding its carriers liable under the policies for coverage of further
investigation and any necessary remediation costs that SIGECO may accrue under
the VRP program and/or related to the site subject to the May 2007
lawsuit. While the total costs that may be incurred in connection
with addressing these sites cannot be determined at this time, SIGECO has
recorded cumulative costs that it reasonably expects to incur totaling
approximately $9.2 million. With respect to insurance coverage,
SIGECO has received and recorded settlements from insurance carriers under
insurance policies in effect when these sites were in operation in an aggregate
amount of $8.1 million.
Environmental
remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants
and other sites have had a minor impact on results of operations or financial
condition since cumulative costs recorded to date approximate PRP and insurance
settlement recoveries. Such cumulative costs are estimated by
management using assumptions based on actual costs incurred, the timing of
expected future payments, and inflation factors, among others. While
the Company’s utilities have recorded all costs which they presently expect to
incur in connection with activities at these sites, it is possible that future
events may require some level of additional remedial activities which are not
presently foreseen and those costs may not be subject to PRP or insurance
recovery. As of March 31, 2009 and December 31, 2008, approximately
$6.0 million and $6.5 million, respectively, of accrued, but not yet spent,
remediation costs are included in Other Liabilities related to
both the Indiana Gas and SIGECO sites.
Rate
and Regulatory Matters
Vectren Energy Delivery of
Ohio, Inc. (VEDO) Gas Base Rate Order Received
On
January 7, 2009, the PUCO issued an order approving the stipulation reached in
the VEDO rate case. The order provides for a rate increase of nearly
$14.8 million, an overall rate of return of 8.89 percent on rate base of about
$235 million; an opportunity to recover costs of a program to accelerate
replacement of cast iron and bare steel pipes, as well as certain service
risers; and base rate recovery of an additional $2.9 million in conservation
program spending.
The order
also 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 does continue once this base rate increase is in
effect. After year one, nearly 90 percent of the combined residential
and commercial base rate margins will be 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,
and all such requests have been denied.
With this
rate order the Company has in place for its Ohio gas territory rates that allow
for the phased implementation of a straight fixed variable rate design that
mitigates both weather risk and lost margin; tracking of bad debt and percent of
income payment plan (PIPP) expenses; base rate recovery of pipeline integrity
management expense; timely recovery of costs associated with the accelerated
replacement of bare steel and cast iron pipes, as well as certain service
risers; and expanded conservation programs now totaling up to $5 million in
annual expenditures.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission
needs of much of the Midwest and maintains operational control over the
Company’s electric transmission facilities as well as that of other Midwest
utilities. Since April 1, 2005, the Company has been an active participant
in the MISO energy markets, bidding its owned generation into the Day Ahead and
Real Time markets and procuring power for its retail customers at Locational
Marginal Pricing (LMP) as determined by the MISO market.
The
Company is typically in a net sales position with MISO as generation capacity is
in excess of that needed to serve native load and is only occasionally in a net
purchase position. When the Company is a net seller such net revenues are
included in Electric Utility
revenues and when the Company is a net purchaser such net purchases are
included in Cost of fuel and
purchased power. Net positions are determined on an hourly
basis. Since the Company became an active MISO member, its generation
optimization strategies primarily involve the sale of excess generation into the
MISO day ahead and real-time markets. Net revenues from wholesale
activities included in Electric Utility revenues
totaled $12.9 million and $21.4 million in the three months ended March 31, 2009
and 2008, respectively.
The
Company also receives transmission revenue that results from other members’ use
of the Company’s transmission system. These revenues are also
included in Electric Utility
revenues. Generally, these transmission revenues along with
costs charged by the MISO are considered components of base rates and any
variance from that included in base rates is recovered/refunded through tracking
mechanisms.
As a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the
nature of MISO’s policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where
MISO began providing a bid-based regulation and contingency operating reserve
markets on January 6, 2009, it is difficult to predict near term operational
impacts. The IURC has approved the Company’s participation in the ASM
and has granted authority to defer costs associated with ASM. 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 $2.1 million for the three months March 31,
2009.
One such
project currently under construction is an interstate 345 kilovolt
transmission line that will connect Vectren’s A B Brown Station to a station in
Indiana owned by Duke Energy to the north and to a station in Kentucky owned by
Big Rivers Electric Corporation to the south. Throughout the project,
SIGECO is to recover an approximate 10 percent return, inclusive of the
FERC approved equity rate of return of 12.38 percent, on capital
investments through a rider mechanism which is updated annually for estimated
costs to be incurred. Of the total investment, which is expected to
approximate $70 million, as of March 31, 2009, the Company has invested
approximately $4.6 million. The Company expects this project to be
operational in 2011. At that time, any operating expenses including
depreciation expense are also expected to be recovered through a FERC approved
rider mechanism. Further, the approval allows for recovery of expenditures
made even in the event currently unforeseen difficulties delay or permanently
halt the project.
Vectren South Electric Lost
Margin Recovery Filing
In 2008,
the Company made an initial filing with the IURC requesting a multi-year program
to promote energy conservation and expanded demand side management programs
within its Vectren South electric utility. As proposed, costs
associated with these programs would be recovered through a tracking
mechanism. The implementation of these programs is designed to work
in tandem with a lost margin recovery mechanism. This mechanism, as
proposed, allows recovery of a portion of rates from residential and commercial
customers based on the level of customer revenues established in Vectren South’s
last electric general rate case. This program is similar to programs
authorized by the IURC in the Company’s Indiana natural gas service
territories. In April of 2009, all filings were completed, and the
Company would expect an IURC decision to occur during 2009.
Results of Operations of the
Nonutility Group
The
Nonutility Group operates in three primary business areas: Energy Marketing and
Services, Coal Mining, and Energy Infrastructure Services. Energy
Marketing and Services markets and supplies natural gas and provides energy
management services. Coal Mining mines and sells
coal. Energy Infrastructure Services provides underground
construction and repair and provides performance contracting and renewable
energy services. There are also other legacy businesses that have
invested in energy-related opportunities and services, real estate, and
leveraged leases, among other investments. The Nonutility Group
supports the Company’s regulated utilities pursuant to service contracts by
providing natural gas supply services, coal, and infrastructure
services. Nonutility Group earnings for the three months ended March
31, 2009 and 2008, follow:
|
|
Three
Months Ended March 31,
|
|
(In
millions, except per share amounts)
|
|
2009
|
|
|
2008
|
|
NET
INCOME
|
|
$ |
16.5 |
|
|
$ |
6.3 |
|
CONTRIBUTION
TO VECTREN BASIC EPS
|
|
$ |
0.20 |
|
|
$ |
0.08 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME ATTRIBUTED TO:
|
|
|
|
|
|
|
|
|
Energy
Marketing & Services
|
|
$ |
15.4 |
|
|
$ |
9.0 |
|
Mining
Operations
|
|
|
2.8 |
|
|
|
(0.9 |
) |
Energy
Infrastructure Services
|
|
|
(0.5 |
) |
|
|
(3.2 |
) |
Other
Businesses
|
|
|
(1.2 |
) |
|
|
1.4 |
|
Energy
Marketing and Services
Energy
Marketing and Services is comprised of the Company’s gas marketing operations,
energy management services, and retail gas supply
operations. Results, inclusive of holding company costs, from Energy
Marketing and Services for the quarter ended March 31, 2009, were earnings of
$15.4 million compared to $9.0 million in 2008.
ProLiance Energy, LLC
(ProLiance)
ProLiance
Energy, a nonutility energy marketing affiliate of Vectren and Citizens,
provides services to a broad range of municipalities, utilities, industrial
operations, schools, and healthcare institutions located throughout the Midwest
and Southeast United States. ProLiance’s customers include Vectren’s
Indiana utilities and nonutility gas supply operations and Citizens’
utilities. ProLiance’s primary businesses include gas marketing, gas
portfolio optimization, and other portfolio and energy management
services. Consistent with its ownership percentage, Vectren is
allocated 61 percent of ProLiance’s profits and losses; however, governance and
voting rights remain at 50 percent for each member; and therefore, the Company
accounts for its investment in ProLiance using the equity method of
accounting. Vectren received regulatory approval on April 25, 2006,
from the IURC for ProLiance to continue to provide natural gas supply services
to the Company’s Indiana utilities through March 2011.
For the
three months ended March 31, 2009 and 2008, the amounts recorded to Equity in earnings of unconsolidated
affiliates related to ProLiance totaled $13.3 million and $14.4 million,
respectively. ProLiance’s net earnings contribution, which consists
of those earnings accounted for using the equity method, less allocated
financing costs and related income taxes effects was $7.0 million compared to
$7.8 million in 2008. The $0.8 million decrease in 2009 compared to
2008 reflects lower margin due to lower seasonal spreads locked in last
year. Current year seasonal spreads have improved and will be
realized in the fourth quarter of 2009 and the first quarter of
2010. ProLiance’s storage capacity is 46 BCF compared to
42 BCF at December 31, 2008.
Regulatory
Matter
ProLiance
self reported to the Federal Energy Regulatory Commission (FERC) in October 2007
possible non-compliance with the FERC’s capacity release
policies. ProLiance has taken corrective actions to assure that
current and future transactions are compliant. ProLiance is committed
to full regulatory compliance and is cooperating fully with the FERC regarding
these issues. ProLiance believes that it has adequately reserved for
this matter. Although the outcome of any legal or regulatory
proceedings resulting from these matters cannot be predicted, the final
resolution of these matters is not expected to have a material impact on the
Company’s consolidated operating results, financial position or cash
flows.
Investment
in Liberty Gas Storage
Liberty
Gas Storage, LLC (Liberty) is a joint venture between a subsidiary of ProLiance
and a subsidiary of Sempra Energy (SE). ProLiance is the minority member
with a 25 percent interest, which it accounts for using the equity method.
Liberty, as currently permitted, is a 17 BCF salt dome facility in southern
Louisiana, near Sulphur, Louisiana. Liberty also owns a second site near
Hackberry, Louisiana with the potential to develop an additional 17 BCF of
storage. ProLiance has a long term contract for approximately 5 Bcf of
working gas capacity. The total project cost incurred at the Sulphur
site through March 31, 2009 is approximately $200 million. ProLiance’s
portion of the cost incurred is approximately $50 million.
In late
2008, SE advised ProLiance that the completion of this phase of Liberty’s
development at the Sulphur site has been delayed by subsurface and
well-completion problems. To date, corrective measures have been
unsuccessful. Among other options, other corrective measures are being
evaluated but it is possible that the salt-cavern facility may not go into
service, or may have reduced capacity when placed in service. ProLiance
estimates the maximum exposure to its investment in the Sulphur site is $35
million. The Company’s proportionate share would be $12 million after
tax. The Company believes that such a charge, should it occur, would
not have a material adverse effect on either the Company’s or ProLiance’s
financial position, cash flows, or liquidity, but it could be material to net
income in any one accounting period. Further, it is not expected that the
delay in Liberty’s development will impact ProLiance’s ability to meet the needs
of its customers.
Vectren
Source
Vectren
Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural
gas and other related products and services to customers opting for choice among
energy providers. Vectren Source earned approximately $8.6 million in
the first quarter of 2009, compared to $2.0 million in 2008, an increase of
approximately $6.6 million. Results were positively impacted by
higher margins. These higher margins resulted primarily from
favorable market conditions, over the course of the quarter as revenues on
variable priced sales contracts fell more slowly than gas costs. Due
to the seasonal nature of the retail gas supply business and due to prices
charged to customers more fully reflecting the current lower gas prices, such
higher earnings are not expected to continue for the remainder of
2009. Vectren Source’s customer count at March 31, 2009 was
approximately 171,000 customers, compared to 157,000 customers at March 31,
2008.
Coal
Mining Operations
Coal
Mining mines and sells coal to the Company’s utility operations and to third
parties through its wholly owned subsidiary Vectren Fuels, Inc.
(Fuels). Coal Mining, inclusive of holding company costs, earned
approximately $2.8 million in the first quarter of 2009, compared to a loss of
$0.9 million in 2008. Coal Mining earnings have increased as expected
as contracts reflecting the higher Illinois Basin coal market prices beginning
January 1st. Contracts
reflecting higher market prices are in place on approximately 70 percent of
2009. The impact of higher revenues have been somewhat offset by
increased costs per ton mined. This anticipated increase in costs
incurred during the first quarter is reflective of efforts to reconfigure the
mining operation at Prosperity mine in order to improve future
productivity. Based on the expected improved productivity and
increasing volumes to be sold, Coal Mining earnings are expected to grow
throughout 2009.
Progress
continues at the underground mines currently under construction near Vincennes,
Indiana. Production is expected to begin in late in the second quarter of 2009,
with the second mine opening in late 2010. Reserves at the two
mines are estimated at 88 million tons of recoverable number-five coal at 11,200
BTU (British thermal units) and less than 6-pound sulfur dioxide. The
reserves at these new mines bring total coal reserves to approximately 120
million tons at March 31, 2009. Once in production, the two new mines
are expected to produce 5 million tons of coal per year. Of the total
$170 million investment management estimates to access the reserves, the Company
has invested $90 million in the new mines through March 31, 2009.
Energy
Infrastructure Services
Energy
Infrastructure Services provides underground construction and repair to utility
infrastructure through Miller Pipeline Corporation (Miller) and energy
performance contracting and renewable energy services through Energy Systems
Group, LLC (ESG). Inclusive of holding company costs, Energy
Infrastructure Services operated at a seasonal loss of $0.5 million during the
quarter ended March 31, 2009, compared to a loss of $3.2 million in
2008.
Miller
Pipeline
Miller’s
2009 year to date loss was $0.4 million compared to a loss of $1.7 million in
2008. The smaller loss is due to favorable weather conditions which
allowed for more efficient completion of winter projects and lower interest
rates.
Energy Systems
Group
ESG
earned approximately $0.1 million year to date in 2009, compared to a loss of
$1.1 million in 2008. Results in 2009 were further favorably impacted
by Energy Efficient Commercial Building federal income tax deductions,
associated with the installation of energy efficient
equipment. Results also reflect higher margin percentages that
include an early completion bonus. At March 31, 2009, ESG’s backlog
was $58 million, compared to $65 million at December 31, 2008 and $43 million at
March 31, 2008. The national focus on a comprehensive energy
strategy as evidenced by the Energy Independence and Security Act of 2007 and
the American Recovery and Reinvestment Act of 2009 is likely to create favorable
conditions for ESG’s growth and resulting earnings.
Other
Businesses
Other
nonutility businesses, which include legacy real estate and other investments,
operated at a loss of $1.2 million in the first quarter of 2009 compared to
earnings of $1.4 million in 2008. The decrease in earnings is
primarily due to favorable adjustments recorded in 2008 related to income tax
true-ups.
Impact of Recently Issued
Accounting Guidance
SFAS
157
On
January 1, 2009, the Company adopted the provisions of SFAS No. 157, “Fair Value
Measurements” (SFAS 157) as they relate to nonfinancial assets and nonfinancial
liabilities that are measured at fair value on a nonrecurring basis, such as the
initial measurement of an asset retirement obligation or the use of fair value
goodwill, intangible assets and long-lived assets impairment
tests. This adoption had no significant impact on the Company’s
operating results or financial condition.
SFAS
160
On
January 1, 2009, the Company adopted SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS
160). SFAS 160 establishes accounting and reporting standards that
require ownership percentages in material subsidiaries held by parties other
than the parent be clearly identified, labeled, and presented separately from
the parent’s equity in the equity section of the consolidated balance sheet; the
amount of consolidated net income attributable to the parent and the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement; that changes in the parent’s ownership
interest while it retains control over its subsidiary be accounted for
consistently; that when a subsidiary is deconsolidated, any retained
noncontrolling equity investment be initially measured at fair value; and that
sufficient disclosure is made to clearly identify and distinguish between the
interests of the parent and the noncontrolling owners. Because of the
diminimus level of entities that are controlled by the Company but are less than
wholly-owned, the adoption of SFAS 160 had a minimal impact to the Company’s
presentation of its financial position and operating results.
SFAS
161
On
January 1, 2009, the Company adopted the qualitative and quantitative
disclosures required in both interim and annual financial statements described
in SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities – an Amendment of FASB Statement No. 133” (SFAS 161). SFAS
161 describes enhanced disclosures under SFAS 133 and requires that objectives
for using derivative instruments be disclosed in terms of underlying risk and
accounting designation in order to better convey the purpose of derivative use
in terms of the risks that the entity is intending to manage. These
disclosures are included in Note 12 to the consolidated condensed financial
statements.
SFAS
141R
On
January 1, 2009, the Company adopted SFAS No. 141, “Business Combinations” (SFAS
141R). SFAS 141R establishes principles and requirements for how the
acquirer of an entity (1) recognizes and measures the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree (2) recognizes and measures acquired goodwill or a bargain purchase
gain and (3) determines what information to disclose in its financial statements
in order to enable users to assess the nature and financial effects of the
business combination. SFAS 141R applies to all transactions or other
events in which one entity acquires control of one or more businesses and
applies to all business entities. Because the provisions of this
standard are applied prospectively, the impact to the Company cannot be
determined until the transactions occur.
FSP
EITF 03-6-1
On
January 1, 2009, the Company adopted FSP EITF 03-6-1, “Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating
Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1 clarified that
unvested share-based payment awards that contain rights to nonforfeitable
dividends participate in undistributed earnings with common shareholders. Awards
of this nature that impact the calculation of EPS are participating
securities. The presence of a participating security requires EPS to
be calculated using the two-class method.
Of the
approximate 81 million shares outstanding as of March 31, 2009, unvested
share-based payment awards that contain rights to nonforfeitable dividends
comprise less than one percent. The Company recently prospectively
changed share-based payment awards such that dividends on awards granted in 2009
and beyond are subject to forfeiture.
As a
result of the insignificant level of participating securities subject to the
two-class method of computing earnings per share, the adoption of FSP EITF
03-6-1 had immaterial impacts to both current and prior period earnings per
share calculations.
EITF
08-05
On
January 1, 2009, the Company adopted EITF Issue No. 08-5, “Issuer's Accounting
for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”
(EITF 08-5). EITF 08-5 states that companies should not include the
effect of third-party credit enhancements in the fair value measurement of the
related liabilities. EITF 08-5 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
March 31, 2009, the Company has approximately $251.1 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. It is not anticipated, the
Company’s valuation techniques will change materially at a result of the
adoption of EITF 08-5.
FASB
Staff Position (FSP) 142-3
In April
2008, the FASB issued FSP No. 142-3, Determination of the Useful Life of
Intangible Assets. FSP No. 142-3 amends the factors that should be
considered in developing renewal or extension assumptions used to determine the
useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible
Assets. The Company adopted FSP No. 142-3 as of January 1, 2009
and such adoption did not have a material impact on the consolidated financial
statements.
FASB
Staff Positions on Fair Value Accounting and Disclosure
In April
2009 the FASB released FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures
about Fair Value of Financial Instruments” (FSP 107-1) to require an entity to
disclose in the body or in the accompanying notes of its summarized financial
information for interim reporting periods and in its financial statements for
annual reporting periods the fair value of all financial instruments for which
it is practicable to estimate that value, whether recognized or not recognized
in the statement of financial position, as required by FASB Statement No.
107. FSP 107-1 is effective for interim reporting periods ending
after June 15, 2009, with early adoption permitted for periods ending after
March 15, 2009. FSP 107-1 does not require disclosures for earlier
periods presented for comparative purposes at initial adoption. In
periods after initial adoption, FSP 107-1 requires comparative disclosures only
for periods ending after initial adoption.
An entity
may early adopt FSP 107-1 only if it also elects to early adopt FSP FAS 157-4,
“Determining Fair Value When the Volume and Level of
Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly which provides additional guidance for
estimating fair value in accordance with FASB Statement No. 157 when the volume
and level of activity for the asset or liability have significantly decreased
and also includes guidance on identifying circumstances that indicate a
transaction is not orderly and FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of
Other-Than-Temporary Impairments” which impacts the impairment testing of
debt securities held for investment purposes and the presentation and disclosure
requirements for debt and equity securities described in FASB Statement
115.
The
Company will adopt these FSP’s for its 2009 second quarter
reporting. It is not expected the impact of adoption will be material
to its cash flows, operations, or financial condition, but will impact interim
period fair value disclosures.
FSP
No. FAS 132(R)-1
In
December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about
Postretirement Benefit Plan Assets” (FSP 132(R)-1). FSP
132(R)-1 amends the plan asset disclosures required under FAS Statement No.
132(R) to provide guidance on an employer’s disclosures about plan assets of a
defined benefit pension or other postretirement plan. Guidance provided by this
FSP relates to disclosures about investment policies and strategies, categories
of plan assets, fair value measurements of plan assets, and significant
concentrations of risk. FSP FAS 132(R)-1 is effective for fiscal years
ending after December 15, 2009. The Company will include FSP FAS 132(R)-1’s
disclosure requirements in its 2009 annual financial statements.
Financial
Condition
Within
Vectren’s consolidated group, Utility Holdings funds the short-term and
long-term financing needs of the Utility Group operations, and Vectren Capital
Corp (Vectren Capital) funds short-term and long-term financing needs of the
Nonutility Group and corporate operations. Vectren Corporation
guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’
debt. Vectren Capital’s long-term and short-term obligations
outstanding at March 31, 2009 approximated $333 million and $81 million,
respectively. Utility Holdings’ outstanding long-term and short-term
borrowing arrangements are jointly and severally guaranteed by Indiana Gas,
SIGECO, and VEDO. Utility Holdings’ long-term and short-term
obligations outstanding at March 31, 2009 approximated $823 million and $33
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.
The
Company’s common stock dividends are primarily funded by utility
operations. Nonutility operations have demonstrated profitability and
the ability to generate cash flows. These cash flows are primarily
reinvested in other nonutility ventures, but are also used to fund a portion of
the Company’s dividends, and from time to time may be reinvested in utility
operations or used for corporate expenses.
The
credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas,
at March 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/A3. Utility Holdings’ commercial paper has a credit rating of
A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s
is stable. These ratings and outlooks have not changed since December
31, 2008. A security rating is not a recommendation to buy, sell, or
hold securities. The rating is subject to revision or withdrawal at
any time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade
rating is BBB- and Baa3, respectively.
The
Company’s consolidated equity capitalization objective is 45-55 percent of
long-term capitalization. This objective may have varied, and will
vary, depending on particular business opportunities, capital spending
requirements, execution of long-term financing plans and seasonal factors that
affect the Company’s operations. The Company’s equity component was
48 percent and 50 percent of long-term capitalization at March 31, 2009 and
December 31, 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
March 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 credit market
volatility. Over the last twelve months, the Company has restored its
short-term borrowing capacity with the completion of several long-term financing
transactions including the issuance of long-term debt in both 2008 and 2009 and
the settlement of an equity forward contract in 2008. The liquidity
provided by these transactions, when coupled with existing cash and expected
internally generated funds, is expected to be sufficient over the near term to
fund anticipated capital expenditures, investments, and debt security
redemptions.
Regarding
debt redemptions, they are insignificant for the remainder of 2009 and total $48
million in 2010. In addition, holders of certain debt instruments have the
one-time option to put $80 million of debt to the Company during the remainder
of 2009 and $10 million in 2010.
Long-term
debt transactions completed in 2009 include a $150 million issuance by Vectren
Capital and a $100 million issuance by Vectren Utility
Holdings. SIGECO also recently remarketed $41.3 million of long-term
debt. These transactions are more fully described below.
Consolidated Short-Term
Borrowing Arrangements
At March
31, 2009, the Company had $905 million of short-term borrowing capacity,
including $520 million for the Utility Group and $385 million for the wholly
owned Nonutility Group and corporate operations. As reduced by
outstanding letters of credit, approximately $445 million was available for the
Utility Group operations and approximately $301 million was available for the
wholly owned Nonutility Group and corporate operations. Of the $520
million in Utility Group capacity, $515 million is available through November,
2010; and of the $385 million in Nonutility capacity, $120 million is available
through September, 2009 and $255 million is available through November,
2010.
Historically,
the Company has 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 continued turmoil and volatility in the financial markets.
As a result, the Company met working capital requirements through a combination
of A2/P2 commercial paper issuances and draws on Utility Holdings’ $515
million commercial paper back-up credit facilities. In
addition, the Company increased its cash investments by approximately $75
million during the fourth quarter of 2008. These cash positions were
liquidated in January 2009 based upon improvements in the short-term debt and
commercial paper markets. Their liquidation resulted in an increase
to the available short-term debt capacity for the Utility Group by $40 million
and for the Nonutility Group by $35 million.
Post March 31, 2009 Utility
Holdings 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 and net of issuance costs totaled
approximately $99.3 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
restrictions contained in the Utility Holdings’ $515 million short-term credit
facility.
As this
issuance occurred after March 31, 2009, its impact of increasing available
short-term capacity and increasing cash on hand is not reflected in the
consolidated balance sheet at March 31, 2009.
ProLiance Short-Term
Borrowing Arrangements
ProLiance,
a nonutility energy marketing affiliate of Vectren and Citizens, has separate
borrowing capacity available through a syndicated credit
facility. The terms of the facility allow for $300 million of
capacity from April 1 through September 30, and $400 million during the October
1 through March 31 heating season, as adjusted for letters of credit and current
inventory and receivable balances. This unutilized capacity, when coupled with
internally generated funds, is expected to provide sufficient liquidity to meet
ProLiance's operational needs. The facility expires June 2009, at
which time, ProLiance anticipates having a new credit facility in place to
support its future working capital requirements. Future working
capital requirements may be less than the level of the current credit line given
the recent decline in natural gas prices. As of March 31, 2009 no
amounts were outstanding. The current facility is not guaranteed by
Vectren or Citizens.
New Share
Issues
The
Company may periodically issue new common shares to satisfy the dividend
reinvestment plan, stock option plan and other employee benefit plan
requirements. New issuances added additional liquidity of $1.5
million in the first quarter of 2009. Throughout 2009, new issuances
required to meet these various plan requirements are estimated to be
approximately $6 million.
Potential
Uses of Liquidity
Planned Capital Expenditures
& Investments
Utility
capital expenditures are estimated at $160 to $180 million for the remainder of
2009. Nonutility capital expenditures and investments, principally
for coal mine development, are estimated at $75 million for the remainder of
2009.
Pension and Postretirement
Funding Obligations
Due to
the recent significant asset value declines experienced by pension plan trusts,
asset values for qualified plans as of December 31, 2008 were approximately 61
percent of the projected benefit obligation. In order to increase the funded
status, management currently estimates the qualified pension plans require
Company contributions of $25 to $30 million in 2009. Under current
market conditions, the Company expects funding a lesser level in
2010. Through March 31, 2009, approximately $4.6 million in
contributions were made.
Other Guarantees and Letters
of Credit
In the
normal course of business, Vectren Corporation issues guarantees supporting the
performance of its consolidated subsidiaries as well as its unconsolidated
affiliates. Such guarantees which contain varying terms generally allow
those subsidiaries and affiliates to execute transactions on more favorable
terms than the subsidiaries and affiliates could obtain without such a
guarantee. Guarantees may include posted letters of credit, leasing
guarantees, and contract performance guarantees.
Related
specifically to guarantees supporting the performance and activities of
unconsolidated affiliates, as of March 31, 2009, such guarantees approximated $3
million. These guarantees relate primarily to arrangements between
ProLiance and various natural gas pipeline operators. The Company has
accrued no liabilities for these unconsolidated affiliate guarantees as they
were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others.”
Credit Contingent
Features
Master
agreements in place with certain counterparties contain provisions involving the
Company’s credit ratings. If ratings were to fall below investment grade,
counterparties to these arrangements could request immediate payment or demand
immediate and ongoing full overnight collateralization on net liability
positions. Currently, contracts to purchase natural gas by the Company’s
nonutility retail gas marketer to fulfill its retail sales are the only
significant derivative-like instruments impacted by credit contingent
features. Such contracts are subject to the NPNS
exclusion. Generally, the natural gas supply period supported by
these arrangements is 60 days, but in some instances, may include forecasted
purchases up to 12 months in advance. If the credit-risk-related
contingent features underlying these agreements were triggered, the Company
would be required to post approximately $5 million of additional collateral at
March 31, 2009.
Comparison
of Historical Sources & Uses of Liquidity
Operating Cash
Flow
The
Company's primary source of liquidity to fund working capital requirements has
been cash generated from operations, which totaled $284.5 million in 2009,
compared to $288.4 million in 2008, a decrease of $3.9 million. The
decrease was primarily due to changes in working capital. This
unfavorable change in working capital principally results from changes in the
timing of natural gas inventory sales and purchases due to exiting the merchant
function in the Ohio service territory in October of 2008. The
decrease was partially offset by higher earnings and other changes.
Financing Cash
Flow
Although
working capital requirements are generally funded by cash flow from operations,
the Company uses short-term borrowings to supplement working capital needs when
accounts receivable balances are at their highest and gas storage is
refilled. Additionally, short-term borrowings are required for
capital projects and investments until they are financed on a long-term
basis.
Net cash
flow required for financing activities was $240.9 million in
2009. The increased cash required for financing activities during
2009 compared to 2008 is reflective of the impact of completed long-term
financing transactions and liquidation of $75 million of cash positions on hand
at the end of 2008.
SIGECO 2009 Debt
Issuance
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.
Vectren Capital Corp. 2009
Debt Issuance
On March
11, 2009, Vectren and Vectren Capital Corp., its wholly-owned subsidiary
(Vectren Capital), entered into a private placement Note Purchase Agreement (the
“2009 Note Purchase Agreement”) pursuant to which various institutional
investors purchased the following tranches of notes from Vectren Capital: (i)
$30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in
6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30
percent senior notes, Series C due 2019. These senior notes are
unconditionally guaranteed by Vectren, the parent of Vectren
Capital. These notes have no sinking fund requirements, and interest
payments are due semi-annually. The proceeds from the sale of the
notes and net of issuance costs totaled approximately $149.0
million.
The 2009
Note Purchase Agreement contains customary representations, warranties and
covenants, including a leverage covenant consistent with leverage covenants
contained in the Vectren Capital $255 million short-term credit
facility.
On March
11, 2009, Vectren and Vectren Capital also entered into a first amendment with
respect to prior note purchase agreements for the remaining outstanding Vectren
Capital debt, other than the $22.5 million series due in 2010, to conform the
covenants in certain respects to those contained in the 2009 Note Purchase
Agreement.
Investing Cash
Flow
Cash flow
required for investing activities was $117.4 million in 2009 and $75.5 million
in 2008. Capital expenditures are the primary component of investing
activities and totaled $117.4 million in 2009, compared to $69.6 million in
2008. The increase in capital expenditures reflects increased
expenditures for coal mine development and also was impacted by the January 2009
ice storm that resulted in approximately $20 million in capital
expenditures.
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:
·
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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.
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·
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Increased
competition in the energy industry, including the effects of industry
restructuring and unbundling.
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·
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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.
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·
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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.
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·
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Economic
conditions including the effects of an economic downturn, inflation rates,
commodity prices, and monetary
fluctuations.
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·
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Economic
conditions surrounding the current recession, which may be more prolonged
and more severe than cyclical downturns, including significantly lower
levels of economic activity; uncertainty regarding energy prices and the
capital and commodity markets; decreases in demand for natural gas,
electricity, coal, and other nonutility products and services; impacts on
both gas and electric large customers; lower residential and commercial
customer counts; higher operating expenses; and further reductions in the
value of certain nonutility real estate and other legacy
investments.
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·
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Increased
natural gas and coal commodity prices and the potential impact on customer
consumption, uncollectible accounts expense, unaccounted for gas and
interest expense.
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·
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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.
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·
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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.
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·
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The
performance of projects undertaken by the Company’s nonutility businesses
and the success of efforts to invest in and develop new opportunities,
including but not limited to, the Company’s coal mining, gas marketing,
and energy infrastructure
strategies.
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·
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Factors
affecting coal mining operations including MSHA guidelines and
interpretations of those guidelines; geologic, equipment, and operational
risks; sales contract negotiations and interpretations; volatile coal
market prices; supplier and contract miner performance; the
availability of key equipment, contract miners and commodities;
availability of transportation; and the ability to access/replace coal
reserves.
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·
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Employee
or contractor workforce factors including changes in key executives,
collective bargaining agreements with union employees, aging workforce
issues, work stoppages, or pandemic
illness.
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·
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Legal
and regulatory delays and other obstacles associated with mergers,
acquisitions and investments in joint
ventures.
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·
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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.
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·
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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.
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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
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The
Company is exposed to various business risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures
are monitored and managed by the Company as an integral part of its overall risk
management program. The Company’s risk management program includes,
among other things, the use of derivatives. The Company 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.
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These
risks are not significantly different from the information set forth in Item 7A
Quantitative and Qualitative Disclosures About Market Risk included in the
Vectren 2008 Form 10-K and is therefore not presented herein.
ITEM
4. CONTROLS AND PROCEDURES
Changes in Internal Controls
over Financial Reporting
During
the quarter ended March 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
March 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 March 31, 2009,
to ensure that information required to be disclosed in reports filed or
submitted under the Exchange Act is:
1)
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recorded,
processed, summarized and reported within the time periods specified in
the SEC’s rules and forms, and
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2)
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accumulated
and communicated to management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
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PART
II. OTHER INFORMATION
ITEM
1. LEGAL PROCEEDINGS
The
Company is party to various legal proceedings arising in the normal course of
business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position, results of operations, or cash
flows. See the notes to the consolidated financial statements
regarding commitments and contingencies, environmental matters, rate and
regulatory matters.
The
consolidated condensed financial statements are included in Part 1 Item
1.
ITEM
1A. RISK FACTORS
Investors
should consider carefully factors that may impact the Company’s operating
results and financial condition, causing them to be materially adversely
affected. The Company’s risk factors have not materially changed from
the information set forth in Item 1A Risk Factors included in the Vectren 2008
Form 10-K and are therefore not presented herein.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
Periodically,
the Company purchases shares from the open market to satisfy share requirements
associated with the Company’s share-based compensation plans; however, no such
open market purchases were made during the quarter ended March 31,
2009.
Exhibits
and Certifications
4.1
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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)
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4.2
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Note
Purchase Agreement, dated March 11, 2009, among Vectren Corporation,
Vectren Capital, Corp. and each of the purchasers named therein. (Filed
and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as
Exhibit 4.5)
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4.3
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First
Amendment, dated March 11, 2009, to Note Purchase Agreement dated October
11, 2005, among Vectren Corporation, Vectren Capital, Corp. and each of
the holders named herein. (Filed and designated in Form 8-K dated March
16, 2009 File No. 1-15467, as Exhibit
4.6)
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4.4
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Second
Amendment, dated March 11, 2009, to Note Purchase Agreement, dated April
25, 1997, among Vectren Corporation, Vectren Capital, Corp. and the holder
named therein as amended by the First Amendment thereto, dated October 11,
2005. (Filed and designated in Form 8-K dated March 16, 2009 File No.
1-15467, as Exhibit 4.7)
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31.1 Certification
Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Executive
Officer
31.2 Certification
Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Financial
Officer
32 Certification Pursuant To Section 906 of The
Sarbanes-Oxley Act Of 2002
Pursuant
to the requirements 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.
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VECTREN
CORPORATION
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Registrant
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May
1, 2009
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/s/Jerome A. Benkert,
Jr.
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Jerome
A. Benkert, Jr.
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Executive
Vice President and Chief Financial Officer
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(Principal
Financial Officer)
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/s/M. Susan
Hardwick
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M.
Susan Hardwick
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Vice
President, Controller and Assistant Treasurer
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(Principal
Accounting
Officer)
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