Ameren Illinois Co - Quarter Report: 2006 September (Form 10-Q)
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(X)
Quarterly
report pursuant to Section 13 or 15(d)
of
the
Securities Exchange Act of 1934
for
the Quarterly Period Ended September 30, 2006
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
|
Exact
name of registrant as specified in its charter;
State
of Incorporation;
Address
and Telephone Number
|
IRS
Employer
Identification
No.
|
1-14756
|
Ameren
Corporation
|
43-1723446
|
(Missouri
Corporation)
|
||
1901
Chouteau Avenue
|
||
St.
Louis, Missouri 63103
|
||
(314)
621-3222
|
||
1-2967
|
Union
Electric Company
|
43-0559760
|
(Missouri
Corporation)
|
||
1901
Chouteau Avenue
|
||
St.
Louis, Missouri 63103
|
||
(314)
621-3222
|
||
1-3672
|
Central
Illinois Public Service Company
|
37-0211380
|
(Illinois
Corporation)
|
||
607
East Adams Street
|
||
Springfield,
Illinois 62739
|
||
(217)
523-3600
|
||
333-56594
|
Ameren
Energy Generating Company
|
37-1395586
|
(Illinois
Corporation)
|
||
1901
Chouteau Avenue
|
||
St.
Louis, Missouri 63103
|
||
(314)
621-3222
|
||
2-95569
|
CILCORP
Inc.
|
37-1169387
|
(Illinois
Corporation)
|
||
300
Liberty Street
|
||
Peoria,
Illinois 61602
|
||
(309)
677-5271
|
||
1-2732
|
Central
Illinois Light Company
|
37-0211050
|
(Illinois
Corporation)
|
||
300
Liberty Street
|
||
Peoria,
Illinois 61602
|
||
(309)
677-5271
|
||
1-3004
|
Illinois
Power Company
|
37-0344645
|
(Illinois
Corporation)
|
||
370
South Main Street
|
||
Decatur,
Illinois 62523
|
||
(217)
424-6600
|
Indicate
by check mark whether the registrants: (1) have 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) have been subject to such filing require-ments
for the past 90 days. Yes (X) No
(
)
Indicate
by check mark whether each registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definitions of accelerated
filer and large accelerated filer in Rule 12b-2 of the Securities Exchange
Act
of 1934.
Large
Accelerated Filer
|
Accelerated
Filer
|
Non-Accelerated
Filer
|
|
Ameren
Corporation
|
(X)
|
(
)
|
(
)
|
Union
Electric Company
|
(
)
|
(
)
|
(X)
|
Central
Illinois Public Service Company
|
(
)
|
(
)
|
(X)
|
Ameren
Energy Generating Company
|
(
)
|
(
)
|
(X)
|
CILCORP
Inc.
|
(
)
|
(
)
|
(X)
|
Central
Illinois Light Company
|
(
)
|
(
)
|
(X)
|
Illinois
Power Company
|
(
)
|
(
)
|
(X)
|
Indicate
by check mark whether each registrant is a shell company (as defined in
Rule
12b-2 of the Securities Exchange Act of 1934).
Ameren
Corporation
|
Yes
|
(
)
|
No
|
(X)
|
Union
Electric Company
|
Yes
|
(
)
|
No
|
(X)
|
Central
Illinois Public Service Company
|
Yes
|
(
)
|
No
|
(X)
|
Ameren
Energy Generating Company
|
Yes
|
(
)
|
No
|
(X)
|
CILCORP
Inc.
|
Yes
|
(
)
|
No
|
(X)
|
Central
Illinois Light Company
|
Yes
|
(
)
|
No
|
(X)
|
Illinois
Power Company
|
Yes
|
(
)
|
No
|
(X)
|
The
number of shares outstanding of each registrant’s classes of common stock as of
November 1, 2006, was as follows:
Ameren
Corporation
|
Common
stock, $.01 par value per share - 206,262,150
|
Union
Electric Company
|
Common
stock, $5 par value per share, held by Ameren
Corporation
(parent company of the registrant) - 102,123,834
|
Central
Illinois Public Service Company
|
Common
stock, no par value, held by Ameren
Corporation
(parent company of the registrant) - 25,452,373
|
Ameren
Energy Generating Company
|
Common
stock, no par value, held by Ameren Energy
Development
Company (parent company of the
registrant
and indirect subsidiary of Ameren
Corporation)
- 2,000
|
CILCORP
Inc.
|
Common
stock, no par value, held by Ameren
Corporation
(parent company of the registrant) - 1,000
|
Central
Illinois Light Company
|
Common
stock, no par value, held by CILCORP Inc.
(parent
company of the registrant and subsidiary of
Ameren
Corporation) - 13,563,871
|
Illinois
Power Company
|
Common
stock, no par value, held by Ameren
Corporation
(parent company of the registrant) -
23,000,000
|
OMISSION
OF CERTAIN INFORMATION
Ameren
Energy Generating Company and CILCORP Inc. meet the conditions set forth
in
General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing
this
form with the reduced disclosure format allowed under that General
Instruction.
This
combined Form 10-Q is separately filed by Ameren Corporation, Union Electric
Company, Central Illinois Public Service Company, Ameren Energy Generating
Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power
Company. Each registrant hereto is filing on its own behalf all of the
information contained in this quarterly report that relates to such registrant.
Each registrant hereto is not filing any information that does not relate
to
such registrant, and therefore makes no representation as to any such
information.
TABLE
OF CONTENTS
Page
|
|
Glossary
of Terms and Abbreviations
|
5
|
Forward-looking
Statements
|
6
|
PART
I Financial
Information
|
|
Item
1. Financial
Statements (Unaudited)
|
|
Ameren
Corporation
|
|
Consolidated
Statement of Income
|
8
|
Consolidated
Balance Sheet
|
9
|
Consolidated
Statement of Cash Flows
|
10
|
Union
Electric Company
|
|
Consolidated
Statement of Income
|
11
|
Consolidated
Balance Sheet
|
12
|
Consolidated
Statement of Cash Flows
|
13
|
Central
Illinois Public Service Company
|
|
Statement
of Income
|
14
|
Balance
Sheet
|
15
|
Statement
of Cash Flows
|
16
|
Ameren
Energy Generating Company
|
|
Consolidated
Statement of Income
|
17
|
Consolidated
Balance Sheet
|
18
|
Consolidated
Statement of Cash Flows
|
19
|
CILCORP
Inc.
|
|
Consolidated
Statement of Income
|
20
|
Consolidated
Balance Sheet
|
21
|
Consolidated
Statement of Cash Flows
|
22
|
Central
Illinois Light Company
|
|
Consolidated
Statement of Income
|
23
|
Consolidated
Balance Sheet
|
24
|
Consolidated
Statement of Cash Flows
|
25
|
Illinois
Power Company
|
|
Consolidated
Statement of Income
|
26
|
Consolidated
Balance Sheet
|
27
|
Consolidated
Statement of Cash Flows
|
28
|
Combined
Notes to Financial Statements
|
29
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
57
|
Item
3. Quantitative
and Qualitative Disclosures About Market Risk
|
82
|
Item
4. Controls
and Procedures
|
85
|
PART
II Other
Information
|
|
Item
1. Legal
Proceedings
|
85
|
Item
1A. Risk
Factors
|
86
|
Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds
|
90
|
Item
6. Exhibits
|
90
|
Signatures
|
92
|
This
Form
10-Q contains “forward-looking” statements within the meaning of Section 21E of
the Securities Exchange Act of 1934, as amended. Forward-looking statements
are
all statements other than statements of historical fact, including those
statements that are identified by the use of the words “anticipates,”
“estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar
expressions. Forward-looking statements should be read with the cautionary
statements and important factors included on page 6 of this Form 10-Q under
the
heading “Forward-looking Statements.”
4
GLOSSARY
OF TERMS AND ABBREVIATIONS
We
use
the words “our,” “we” or “us” with respect to certain information that relates
to all Ameren Companies, as defined below. When appropriate, subsidiaries
of
Ameren are named specifically as we discuss their various business
activities.
AERG
-
AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates
a
non-rate-regulated electric generation business in Illinois.
AFS
-
Ameren
Energy Fuels and Services Company, a Development Company subsidiary that
procures fuel and natural gas and manages the related risks for the Ameren
Companies.
Ameren
-
Ameren
Corporation and its subsidiaries on a consolidated basis. In references
to
financing activities, acquisition activities, or liquidity arrangements,
Ameren
is defined as Ameren Corporation, the parent.
Ameren
Companies -
The
individual registrants within the Ameren consolidated group.
Ameren
Energy -
Ameren
Energy, Inc., an Ameren Corporation subsidiary that is a power marketing
and
risk management agent for affiliated companies. Beginning in 2007, Ameren
Energy
will only serve UE.
Ameren
Illinois utilities
- CIPS,
CILCO and IP.
Ameren
Services - Ameren
Services Company, an Ameren Corporation subsidiary that provides support
services to Ameren and its subsidiaries.
APB
-
Accounting Principles Board.
ARO
- Asset
retirement obligations.
Baseload
- The
minimum amount of electric power delivered or required over a given period
of
time at a steady rate.
Capacity
factor
- A
percentage measure that indicates how much of an electric power generating
unit’s capacity was used during a specific period.
CILCO
-
Central
Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated
electric transmission and distribution business, a primarily non-rate-regulated
electric generation business through AERG, and a rate-regulated natural
gas
transmission and distribution business, all in Illinois, as AmerenCILCO.
CILCO
owns all of the common stock of AERG.
CILCORP
-
CILCORP
Inc., an Ameren Corporation subsidiary that operates as a holding company
for
CILCO and various non-rate-regulated subsidiaries.
CIPS
-
Central
Illinois Public Service Company, an Ameren Corporation subsidiary that
operates
a rate-regulated electric and natural gas transmission and distribution
business
in Illinois as AmerenCIPS.
Cooling
degree-days
- The
summation of positive differences between the mean daily temperature and
a
65-degree
Fahrenheit base. The statistic is useful as an indicator of demand for
electricity for summer space cooling for residential and commercial
customers.
CT
-
Combustion turbine electric generation equipment used primarily for peaking
capacity.
CUB
-
Citizens Utility Board.
Development
Company -
Ameren
Energy Development Company, a Resources Company subsidiary, and Genco and
Marketing Company parent.
DOE
-
Department of Energy, a U.S. government agency.
DRPlus
-
Ameren
Corporation’s dividend reinvestment and direct stock purchase plan.
Dynegy
-
Dynegy
Inc.
DYPM
-
Dynegy
Power Marketing, Inc., a Dynegy subsidiary.
EEI
-
Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40%
owned by
UE and 40% owned by Development Company) that operates non-rate-regulated
electric generation and electric transmission facilities in Illinois. The
remaining 20% is owned by Kentucky Utilities Company.
ELPC
-
Environmental Law and Policy Center.
EPA
-
Environmental Protection Agency, a U.S. government agency.
Exchange
Act -
Securities Exchange Act of 1934, as amended.
FASB
-
Financial Accounting Standards Board, a rulemaking organization that establishes
financial accounting and reporting standards in the United States.
FERC
-
The
Federal Energy Regulatory Commission, a U.S. government agency.
FIN
-
FASB
Interpretation. A FIN statement is an explanation intended to clarify accounting
pronouncements previously issued by the FASB.
Fitch
- Fitch
Ratings, a credit rating agency.
GAAP
-
Generally accepted accounting principles in the United States.
Genco
-
Ameren
Energy Generating Company, a Development Company subsidiary that operates
a
non-rate-regulated electric generation business in Illinois and
Missouri.
Gigawatthour
-
One
thousand megawatthours.
Heating
degree-days -
The
summation of negative differences between the mean daily temperature and
a 65-
degree Fahrenheit base. This statistic is useful as an indicator of demand
for
electricity and natural gas for winter space heating for residential and
commercial customers.
ICC
-
Illinois Commerce Commission, a state agency that regulates the Illinois
utility
businesses and operations of CIPS, CILCO, and IP.
Illinois
Customer Choice Law -
Illinois Electric Service Customer Choice and Rate Relief Law of 1997,
which
provided for electric utility restructuring and introduced competition
into the
retail supply of electric energy in Illinois.
Illinois
EPA
-
Illinois Environmental Protection Agency, a state government
agency.
Illinois
Regulated
- A
financial reporting segment consisting of the regulated electric and gas
transmission and distribution businesses of CIPS, CILCO and IP.
5
IP
- Illinois
Power Company, an Ameren Corporation subsidiary that was acquired from
Dynegy on
September 30, 2004. IP operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois as AmerenIP.
IP
SPT
-
Illinois Power Special Purpose Trust, which was created as a subsidiary
of
Illinois Power Securitization Limited Liability Company to issue Transitional
Funding Trust Notes as allowed under the Illinois Customer Choice Law.
Pursuant
to FIN 46R, IP SPT is a variable-interest entity, as the equity investment
is
not sufficient to permit IP SPT to finance its activities without additional
subordinated debt.
JDA
- The
joint dispatch agreement among UE, CIPS, and Genco under which UE and Genco
jointly dispatch electric generation. This agreement will terminate on
December
31, 2006.
Kilowatthour
- A
measure
of electricity consumption equivalent to the use of 1,000 watts of power
over a
period of one hour.
Marketing
Company - Ameren
Energy Marketing Company, a Development Company subsidiary that markets
power
for Genco, AERG and EEI primarily for periods over one year.
Medina
Valley
-
AmerenEnergy Medina
Valley Cogen (No. 4) LLC and its subsidiaries, which are all Development
Company
subsidiaries and indirectly own a 40-megawatt gas-fired electric generation
plant.
Megawatthour
-
One
thousand kilowatthours.
MGP
- Manufactured
gas plant.
MISO
- Midwest
Independent Transmission System Operator, Inc.
Missouri
Regulated
- A
financial reporting segment consisting of all the operations of UE’s business
except for UE’s 40% interest in EEI and other non-rate-regulated
activities.
MISO
Day Two Energy Market - A
market
that began operating on April 1, 2005. It uses market-based pricing,
incorporating transmission congestion and line losses, to compensate market
participants for power. The previous system required generators to make
advance
reservations for transmission service.
Money
pool - Borrowing
agreements among Ameren and its subsidiaries to coordinate and provide
for
certain short-term cash and working capital requirements. Separate money
pools
are maintained between rate-regulated and non-rate-regulated businesses.
These
are referred to as the utility money pool and the non-state-regulated subsidiary
money pool, respectively.
Moody’s
- Moody’s
Investors Service Inc., a credit rating agency.
MoPSC
-
Missouri Public Service Commission, a state agency that regulates the Missouri
utility business and operations of UE.
Non-rate-regulated
Generation
- A
financial reporting segment consisting of the operations or activities
of Genco,
CILCORP holding company, AERG, EEI and Marketing Company.
NOx - Nitrogen
oxide.
Noranda
-
Noranda Aluminum, Inc.
NYMEX
-
New
York Mercantile Exchange.
OCI
- Other
comprehensive income (loss) as defined by GAAP.
PUHCA
1935 -
The
Public Utility Holding Company Act of 1935, which was repealed, effective
February 8, 2006, by the Energy Policy Act of 2005 that was enacted on
August 8,
2005.
PUHCA
2005
- The
Public Utility Holding Company Act of 2005, that was enacted as part of
the
Energy Policy Act of 2005, effective February 8, 2006.
Resources
Company -
Ameren
Energy Resources Company, an Ameren Corporation subsidiary that consists
of
non-rate-regulated operations, including Development Company, Genco, Marketing
Company, AFS, and Medina Valley.
S&P
-
Standard & Poor’s Ratings Services, a credit rating agency that is a
division of The McGraw Hill Companies, Inc.
SEC
-
Securities and Exchange Commission, a U.S. government agency.
SFAS
- Statement
of Financial Accounting Standards, the accounting and financial reporting
rules
issued by the FASB.
SO2
- Sulfur
dioxide.
UE
- Union
Electric Company, an Ameren Corporation subsidiary that operates a
rate-regulated electric generation, transmission and distribution business,
and
a rate-regulated natural gas transmission and distribution business in
Missouri,
as AmerenUE.
_________________________________________________
FORWARD-LOOKING
STATEMENTS
Statements
in this report not based on historical facts are considered “forward-looking”
and, accordingly, involve risks and uncertainties that could cause actual
results to differ materially from those discussed. Although such forward-looking
statements have been made in good faith and are based on reasonable assumptions,
there is no assurance that the expected results will be achieved. These
statements include (without limitation) statements as to future expectations,
beliefs, plans, strategies, objectives, events, conditions, and financial
performance. In connection with the “safe harbor” provisions of the Private
Securities Litigation Reform Act of 1995, we are providing this cautionary
statement to identify important factors that could cause actual results
to
differ materially from those anticipated. The following factors, in addition
to
those discussed elsewhere in this report and in our other filings with
the SEC,
could cause actual results to differ materially from management expectations
suggested in such forward-looking statements:
· |
regulatory
or legislative actions, including changes in regulatory policies
and
ratemaking determinations, such
|
6
as
the outcome of UE, CIPS, CILCO and IP rate proceedings or the
enactment of an extension of an electric rate freeze or similar action that
impairs the full and timely recovery
of
costs in Illinois;
· |
the
impact of the termination of the
JDA;
|
· |
changes
in laws and other governmental actions, including monetary and fiscal
policies;
|
· |
the
effects of increased competition in the future due to, among other
things,
deregulation of certain aspects of our business at both the state
and
federal levels, and the implementation of deregulation, such as when
the
current electric rate freeze and current power supply contracts expire
in
Illinois at the end of 2006;
|
· |
the
effects of participation in the
MISO;
|
· |
the
availability of fuel such as coal, natural gas and enriched uranium
used
to produce electricity; the availability of purchased power and natural
gas for distribution; and the level and volatility of future market
prices
for such commodities, including the ability to recover the costs
for such
commodities;
|
· |
the
effectiveness of our risk management strategies and the use of financial
and derivative instruments;
|
· |
prices
for power in the Midwest;
|
· |
business
and economic conditions, including their impact on interest rates;
|
· |
disruptions
of the capital markets or other events that make the Ameren Companies’
access to necessary capital more difficult or
costly;
|
· |
the
impact of the adoption of new accounting standards and the application
of
appropriate technical accounting rules and guidance;
|
· |
actions
of credit rating agencies and the effects of such actions;
|
· |
weather
conditions and other natural phenomena;
|
· |
the
impact of system outages caused by severe weather conditions or other
events;
|
· |
generation
plant construction, installation and performance, including costs
associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident
and its future operation;
|
· |
operation
of UE’s nuclear power facility, including planned and unplanned outages,
and decommissioning costs;
|
· |
the
effects of strategic initiatives, including acquisitions and divestitures;
|
· |
the
impact of current environmental regulations on utilities and power
generating companies and the expectation that more stringent requirements
will be introduced over time, which could have a negative financial
effect;
|
· |
labor
disputes and future wage and employee benefits costs, including changes
in
returns on benefit plan assets;
|
· |
changes
in the energy markets, environmental laws or regulations, interest
rates,
or other factors that could adversely affect assumptions in connection
with the IP acquisition;
|
· |
the
impact of conditions imposed by regulators in connection with their
approval of Ameren’s acquisition of
IP;
|
· |
the
inability of our counterparties and affiliates to meet their obligations
with respect to contracts and financial instruments;
|
· |
the
cost and availability of transmission capacity for the energy generated
by
the Ameren Companies’ facilities or required to satisfy energy sales made
by the Ameren Companies;
|
· |
legal
and administrative proceedings; and
|
· |
acts
of sabotage, war, terrorism or intentionally disruptive acts.
|
Given
these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements to reflect new information or future
events.
7
PART
I. FINANCIAL INFORMATION
ITEM
1. FINANCIAL
STATEMENTS
AMEREN
CORPORATION
|
|||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
|||||||||||||
(Unaudited)
(In millions, except per share amounts)
|
|||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
Operating
Revenues:
|
|||||||||||||
Electric
|
$
|
1,767
|
$
|
1,732
|
$
|
4,356
|
$
|
4,257
|
|||||
Gas
|
143
|
149
|
904
|
819
|
|||||||||
Other
|
-
|
-
|
-
|
3
|
|||||||||
Total
operating revenues
|
1,910
|
1,881
|
5,260
|
5,079
|
|||||||||
Operating
Expenses:
|
|||||||||||||
Fuel
and purchased power
|
623
|
634
|
1,672
|
1,524
|
|||||||||
Gas
purchased for resale
|
84
|
90
|
641
|
550
|
|||||||||
Other
operations and maintenance
|
395
|
392
|
1,137
|
1,112
|
|||||||||
Depreciation
and amortization
|
162
|
158
|
489
|
472
|
|||||||||
Taxes
other than income taxes
|
99
|
98
|
302
|
284
|
|||||||||
Total
operating expenses
|
1,363
|
1,372
|
4,241
|
3,942
|
|||||||||
Operating
Income
|
547
|
509
|
1,019
|
1,137
|
|||||||||
Other
Income and Expenses:
|
|||||||||||||
Miscellaneous
income
|
5
|
6
|
13
|
19
|
|||||||||
Miscellaneous
expense
|
(3
|
)
|
(1
|
)
|
(4
|
)
|
(7
|
)
|
|||||
Total
other income
|
2
|
5
|
9
|
12
|
|||||||||
Interest
Charges
|
82
|
70
|
238
|
221
|
|||||||||
Income
Before Income Taxes, Minority Interest
|
|||||||||||||
and
Preferred Dividends of Subsidiaries
|
467
|
444
|
790
|
928
|
|||||||||
Income
Taxes
|
161
|
159
|
273
|
330
|
|||||||||
Income
Before Minority Interest and Preferred
|
|||||||||||||
Dividends
of Subsidiaries
|
306
|
285
|
517
|
598
|
|||||||||
Minority
Interest and Preferred Dividends
|
|||||||||||||
of
Subsidiaries
|
(13
|
)
|
(5
|
)
|
(31
|
)
|
(12
|
)
|
|||||
Net
Income
|
$
|
293
|
$
|
280
|
$
|
486
|
$
|
586
|
|||||
Earnings
per Common Share – Basic and Diluted
|
$
|
1.42
|
$
|
1.37
|
$
|
2.37
|
$
|
2.94
|
|||||
Dividends
per Common Share
|
$
|
0.635
|
$
|
0.635
|
$
|
1.905
|
$
|
1.905
|
|||||
Average
Common Shares Outstanding
|
205.9
|
203.8
|
205.4
|
199.6
|
|||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
8
AMEREN
CORPORATION
|
||||||
CONSOLIDATED
BALANCE SHEET
|
||||||
(Unaudited)
(In millions, except per share amounts)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
34
|
$
|
96
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $13 and $22, respectively)
|
463
|
552
|
||||
Unbilled
revenue
|
267
|
382
|
||||
Miscellaneous
accounts and notes receivable
|
116
|
31
|
||||
Materials
and supplies
|
710
|
572
|
||||
Other
current assets
|
147
|
185
|
||||
Total
current assets
|
1,737
|
1,818
|
||||
Property
and Plant, Net
|
14,028
|
13,572
|
||||
Investments
and Other Assets:
|
||||||
Investments
in leveraged leases
|
31
|
50
|
||||
Nuclear
decommissioning trust fund
|
271
|
250
|
||||
Goodwill
|
976
|
976
|
||||
Intangible
assets
|
228
|
246
|
||||
Other
assets
|
753
|
419
|
||||
Regulatory
assets
|
806
|
831
|
||||
Total
investments and other assets
|
3,065
|
2,772
|
||||
TOTAL
ASSETS
|
$
|
18,830
|
$
|
18,162
|
||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
465
|
$
|
96
|
||
Short-term
debt
|
311
|
193
|
||||
Accounts
and wages payable
|
382
|
706
|
||||
Taxes
accrued
|
249
|
131
|
||||
Other
current liabilities
|
433
|
361
|
||||
Total
current liabilities
|
1,840
|
1,487
|
||||
Long-term
Debt, Net
|
5,349
|
5,354
|
||||
Preferred
Stock of Subsidiary Subject to Mandatory
Redemption
|
18
|
19
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes, net
|
2,013
|
1,969
|
||||
Accumulated
deferred investment tax credits
|
121
|
129
|
||||
Regulatory
liabilities
|
1,205
|
1,132
|
||||
Asset
retirement obligations
|
538
|
518
|
||||
Accrued
pension and other postretirement benefits
|
840
|
760
|
||||
Other
deferred credits and liabilities
|
144
|
218
|
||||
Total
deferred credits and other liabilities
|
4,861
|
4,726
|
||||
Preferred
Stock of Subsidiaries Not Subject to Mandatory
Redemption
|
195
|
195
|
||||
Minority
Interest in Consolidated Subsidiaries
|
19
|
17
|
||||
Commitments
and Contingencies (Notes 2, 8 and 9)
|
||||||
Stockholders'
Equity:
|
||||||
Common
stock, $.01 par value, 400.0 shares authorized,
|
||||||
206.2
and 204.7 shares outstanding, respectively
|
2
|
2
|
||||
Other
paid-in capital, principally premium on common stock
|
4,478
|
4,399
|
||||
Retained
earnings
|
2,094
|
1,999
|
||||
Accumulated
other comprehensive loss
|
(23
|
)
|
(24
|
)
|
||
Other
|
(3
|
)
|
(12
|
)
|
||
Total
stockholders’ equity
|
6,548
|
6,364
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
18,830
|
$
|
18,162
|
||
The
accompanying notes are an integral part of these consolidated financial
statements.
9
AMEREN
CORPORATION
|
||||||
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
|
||||||
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
486
|
$
|
586
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
507
|
499
|
||||
Amortization
of nuclear fuel
|
26
|
25
|
||||
Amortization
of debt issuance costs and premium/discounts
|
12
|
11
|
||||
Deferred
income taxes and investment tax credits, net
|
7
|
83
|
||||
Loss
on sale of leveraged leases
|
4
|
-
|
||||
Gain
on sales of emission allowances
|
(25
|
)
|
(4
|
)
|
||
Minority
interest
|
23
|
1
|
||||
Other
|
17
|
3
|
||||
Changes
in assets and liabilities, excluding the effects of
acquisitions:
|
||||||
Receivables,
net
|
157
|
(1
|
)
|
|||
Materials
and supplies
|
(136
|
)
|
(94
|
)
|
||
Accounts
and wages payable
|
(289
|
)
|
(72
|
)
|
||
Taxes
accrued
|
148
|
172
|
||||
Assets,
other
|
(97
|
)
|
(28
|
)
|
||
Liabilities,
other
|
101
|
(11
|
)
|
|||
Pension
and other postretirement benefit obligations, net
|
89
|
7
|
||||
Net
cash provided by operating activities
|
1,030
|
1,177
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(666
|
)
|
(660
|
)
|
||
Acquisitions,
net of cash acquired
|
-
|
12
|
||||
CT
acquisitions
|
(292
|
)
|
-
|
|||
Nuclear
fuel expenditures
|
(37
|
)
|
(16
|
)
|
||
Proceeds
from sale of leveraged leases
|
11
|
-
|
||||
Purchases
of emission allowances
|
(38
|
)
|
(92
|
)
|
||
Sales
of emission allowances
|
12
|
4
|
||||
Other
|
5
|
16
|
||||
Net
cash used in investing activities
|
(1,005
|
)
|
(736
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(391
|
)
|
(383
|
)
|
||
Capital
issuance costs
|
(4
|
)
|
(4
|
)
|
||
Short-term
debt, net
|
118
|
(394
|
)
|
|||
Borrowings
from credit facility
|
40
|
-
|
||||
Dividends
paid to minority interest
|
(21
|
)
|
-
|
|||
Redemptions,
repurchases, and maturities:
|
||||||
Long-term
debt
|
(138
|
)
|
(262
|
)
|
||
Preferred
stock
|
(1
|
)
|
(1
|
)
|
||
Issuances:
|
||||||
Common
stock
|
78
|
430
|
||||
Long-term
debt
|
232
|
382
|
||||
Net
cash used in financing activities
|
(87
|
)
|
(232
|
)
|
||
Net
change in cash and cash equivalents
|
(62
|
)
|
209
|
|||
Cash
and cash equivalents at beginning of year
|
96
|
69
|
||||
Cash
and cash equivalents at end of period
|
$
|
34
|
$
|
278
|
||
The
accompanying notes are an integral part of these consolidated financial
statements.
10
UNION
ELECTRIC COMPANY
|
||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
||||||||||||
(Unaudited)
(In millions)
|
||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
836
|
$
|
876
|
$
|
2,090
|
$
|
2,134
|
||||
Gas
|
20
|
19
|
111
|
120
|
||||||||
Other
|
1
|
-
|
2
|
-
|
||||||||
Total
operating revenues
|
857
|
895
|
2,203
|
2,254
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
214
|
261
|
598
|
586
|
||||||||
Gas
purchased for resale
|
10
|
8
|
66
|
66
|
||||||||
Other
operations and maintenance
|
214
|
199
|
581
|
573
|
||||||||
Depreciation
and amortization
|
82
|
79
|
243
|
231
|
||||||||
Taxes
other than income taxes
|
66
|
66
|
184
|
180
|
||||||||
Total
operating expenses
|
586
|
613
|
1,672
|
1,636
|
||||||||
Operating
Income
|
271
|
282
|
531
|
618
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
2
|
3
|
6
|
12
|
||||||||
Miscellaneous
expense
|
(3
|
)
|
(2
|
)
|
(7
|
)
|
(6
|
)
|
||||
Total
other income (expense)
|
(1
|
)
|
1
|
(1
|
)
|
6
|
||||||
Interest
Charges
|
35
|
29
|
107
|
81
|
||||||||
Income
Before Income Taxes and Equity
|
||||||||||||
in
Income of Unconsolidated Investment
|
235
|
254
|
423
|
543
|
||||||||
Income
Taxes
|
92
|
91
|
161
|
193
|
||||||||
Income
Before Equity in Income
|
||||||||||||
of
Unconsolidated Investment
|
143
|
163
|
262
|
350
|
||||||||
Equity
in Income of Unconsolidated Investment
|
23
|
1
|
47
|
3
|
||||||||
Net
Income
|
166
|
164
|
309
|
353
|
||||||||
Preferred
Stock Dividends
|
1
|
1
|
4
|
4
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
165
|
$
|
163
|
$
|
305
|
$
|
349
|
||||
The
accompanying notes as they relate to UE are an integral part of these
consolidated financial statements.
11
UNION
ELECTRIC COMPANY
|
||||||
CONSOLIDATED
BALANCE SHEET
|
||||||
(Unaudited)
(In millions, except per share amounts)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
2
|
$
|
20
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $5 and $6, respectively)
|
196
|
190
|
||||
Unbilled
revenue
|
105
|
133
|
||||
Miscellaneous
accounts and notes receivable
|
84
|
7
|
||||
Accounts
receivable – affiliates
|
35
|
53
|
||||
Current
portion of intercompany note receivable – CIPS
|
-
|
6
|
||||
Materials
and supplies
|
236
|
199
|
||||
Other
current assets
|
59
|
57
|
||||
Total
current assets
|
717
|
665
|
||||
Property
and Plant, Net
|
7,756
|
7,379
|
||||
Investments
and Other Assets:
|
||||||
Nuclear
decommissioning trust fund
|
271
|
250
|
||||
Intercompany
note receivable – CIPS
|
-
|
61
|
||||
Intangible
assets
|
63
|
63
|
||||
Other
assets
|
565
|
269
|
||||
Regulatory
assets
|
562
|
590
|
||||
Total
investments and other assets
|
1,461
|
1,233
|
||||
TOTAL
ASSETS
|
$
|
9,934
|
$
|
9,277
|
||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
10
|
$
|
4
|
||
Short-term
debt
|
208
|
80
|
||||
Accounts
and wages payable
|
119
|
274
|
||||
Accounts
payable – affiliates
|
141
|
134
|
||||
Taxes
accrued
|
214
|
59
|
||||
Other
current liabilities
|
176
|
96
|
||||
Total
current liabilities
|
868
|
647
|
||||
Long-term
Debt, Net
|
2,932
|
2,698
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes, net
|
1,286
|
1,277
|
||||
Accumulated
deferred investment tax credits
|
91
|
96
|
||||
Regulatory
liabilities
|
815
|
802
|
||||
Asset
retirement obligations
|
484
|
466
|
||||
Accrued
pension and other postretirement benefits
|
238
|
203
|
||||
Other
deferred credits and liabilities
|
51
|
72
|
||||
Total
deferred credits and other liabilities
|
2,965
|
2,916
|
||||
Commitments
and Contingencies (Notes 2, 8 and 9)
|
||||||
Stockholders'
Equity:
|
||||||
Common
stock, $5 par value, 150.0 shares authorized – 102.1 shares
outstanding
|
511
|
511
|
||||
Preferred
stock not subject to mandatory redemption
|
113
|
113
|
||||
Other
paid-in capital, principally premium on common stock
|
736
|
733
|
||||
Retained
earnings
|
1,839
|
1,689
|
||||
Accumulated
other comprehensive loss
|
(30
|
)
|
(30
|
)
|
||
Total
stockholders' equity
|
3,169
|
3,016
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
9,934
|
$
|
9,277
|
||
The
accompanying notes as they relate to UE are an integral part of these
consolidated financial statements.
12
UNION
ELECTRIC COMPANY
|
||||||
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
309
|
$
|
353
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
243
|
231
|
||||
Amortization
of nuclear fuel
|
26
|
25
|
||||
Amortization
of debt issuance costs and premium/discounts
|
4
|
3
|
||||
Deferred
income taxes and investment tax credits, net
|
(10
|
)
|
27
|
|||
Gain
on sales of emission allowances
|
(2
|
)
|
(2
|
)
|
||
Other
|
-
|
12
|
||||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
(34
|
) |
(96
|
)
|
||
Materials
and supplies
|
(35
|
)
|
2
|
|||
Accounts
and wages payable
|
(127
|
)
|
44
|
|||
Taxes
accrued
|
174
|
130
|
||||
Assets,
other
|
(52
|
) |
(14
|
)
|
||
Liabilities,
other
|
62
|
(2
|
)
|
|||
Pension
and other postretirement benefit obligations, net
|
35
|
(1
|
)
|
|||
Net
cash provided by operating activities
|
593
|
712
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(325
|
)
|
(388
|
)
|
||
CT
acquisitions from nonaffiliates
|
(292
|
)
|
-
|
|||
CT
acquisitions from Genco
|
-
|
(241
|
)
|
|||
Nuclear
fuel expenditures
|
(37
|
)
|
(16
|
)
|
||
Changes
in money pool advances
|
-
|
-
|
||||
Proceeds
from intercompany note receivable - CIPS
|
67
|
-
|
||||
Sales
of emission allowances
|
2
|
2
|
||||
Other
|
1
|
10
|
||||
Net
cash used in investing activities
|
(584
|
)
|
(633
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(154
|
)
|
(209
|
)
|
||
Dividends
on preferred stock
|
(4
|
)
|
(4
|
)
|
||
Capital
issuance costs
|
-
|
(3
|
)
|
|||
Changes
in short-term debt, net
|
128
|
(375
|
)
|
|||
Changes
in money pool borrowings
|
-
|
79
|
||||
Issuance
of long-term debt
|
-
|
382
|
||||
Capital
contribution from parent
|
3
|
4
|
||||
Net
cash used in financing activities
|
(27
|
)
|
(126
|
)
|
||
Net
change in cash and cash equivalents
|
(18
|
)
|
(47
|
)
|
||
Cash
and cash equivalents at beginning of year
|
20
|
48
|
||||
Cash
and cash equivalents at end of period
|
$
|
2
|
$
|
1
|
||
The
accompanying notes as they relate to UE are an integral part of these
consolidated financial statements.
13
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
|
||||||||||||
STATEMENT
OF INCOME
|
||||||||||||
(Unaudited)
(In millions)
|
||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
228
|
$
|
244
|
$
|
569
|
$
|
542
|
||||
Gas
|
23
|
22
|
150
|
133
|
||||||||
Other
|
3
|
1
|
4
|
2
|
||||||||
Total
operating revenues
|
254
|
267
|
723
|
677
|
||||||||
Operating
Expenses:
|
||||||||||||
Purchased
power
|
125
|
140
|
355
|
331
|
||||||||
Gas
purchased for resale
|
11
|
12
|
99
|
86
|
||||||||
Other
operations and maintenance
|
41
|
39
|
117
|
109
|
||||||||
Depreciation
and amortization
|
16
|
17
|
47
|
45
|
||||||||
Taxes
other than income taxes
|
9
|
9
|
30
|
24
|
||||||||
Total
operating expenses
|
202
|
217
|
648
|
595
|
||||||||
Operating
Income
|
52
|
50
|
75
|
82
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
4
|
4
|
13
|
13
|
||||||||
Miscellaneous
expense
|
-
|
(1
|
)
|
(1
|
)
|
(5
|
)
|
|||||
Total
other income
|
4
|
3
|
12
|
8
|
||||||||
Interest
Charges
|
8
|
7
|
23
|
22
|
||||||||
Income
Before Income Taxes
|
48
|
46
|
64
|
68
|
||||||||
Income
Taxes
|
19
|
15
|
21
|
22
|
||||||||
Net
Income
|
29
|
31
|
43
|
46
|
||||||||
Preferred
Stock Dividends
|
1
|
1
|
2
|
2
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
28
|
$
|
30
|
$
|
41
|
$
|
44
|
||||
The
accompanying notes as they relate to CIPS are an integral part of
these financial statements.
14
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
|
||||||
BALANCE
SHEET
|
||||||
(Unaudited)
(In millions)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
-
|
$
|
-
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $2 and $4, respectively)
|
58
|
70
|
||||
Unbilled
revenue
|
44
|
71
|
||||
Accounts
receivable – affiliates
|
4
|
18
|
||||
Current
portion of intercompany note receivable – Genco
|
37
|
34
|
||||
Current
portion of intercompany tax receivable – Genco
|
10
|
10
|
||||
Advances
to money pool
|
18
|
-
|
||||
Materials
and supplies
|
82
|
75
|
||||
Other
current assets
|
22
|
28
|
||||
Total
current assets
|
275
|
306
|
||||
Property
and Plant, Net
|
1,150
|
1,130
|
||||
Investments
and Other Assets:
|
||||||
Intercompany
note receivable – Genco
|
126
|
163
|
||||
Intercompany
tax receivable – Genco
|
118
|
125
|
||||
Other
assets
|
31
|
24
|
||||
Regulatory
assets
|
35
|
36
|
||||
Total
investments and other assets
|
310
|
348
|
||||
TOTAL
ASSETS
|
$
|
1,735
|
$
|
1,784
|
||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
-
|
$
|
20
|
||
Accounts
and wages payable
|
31
|
36
|
||||
Accounts
payable – affiliates
|
65
|
65
|
||||
Borrowings
from money pool
|
-
|
2
|
||||
Current
portion of intercompany note payable – UE
|
-
|
6
|
||||
Taxes
accrued
|
28
|
26
|
||||
Other
current liabilities
|
43
|
43
|
||||
Total
current liabilities
|
167
|
198
|
||||
Long-term
Debt, Net
|
471
|
410
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes and investment tax credits, net
|
289
|
302
|
||||
Intercompany
note payable – UE
|
-
|
61
|
||||
Regulatory
liabilities
|
218
|
208
|
||||
Accrued
pension and other postretirement benefits
|
13
|
7
|
||||
Other
deferred credits and liabilities
|
21
|
29
|
||||
Total
deferred credits and other liabilities
|
541
|
607
|
||||
Commitments
and Contingencies (Notes 2 and 8)
|
||||||
Stockholders'
Equity:
|
||||||
Common
stock, no par value, 45.0 shares authorized – 25.5 shares
outstanding
|
-
|
-
|
||||
Other
paid-in capital
|
190
|
189
|
||||
Preferred
stock not subject to mandatory redemption
|
50
|
50
|
||||
Retained
earnings
|
321
|
329
|
||||
Accumulated
other comprehensive income (loss)
|
(5
|
)
|
1
|
|||
Total
stockholders' equity
|
556
|
569
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
1,735
|
$
|
1,784
|
||
The
accompanying notes as they relate to CIPS are an integral part of
these financial statements.
15
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
|
||||||
STATEMENT
OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
43
|
$
|
46
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
47
|
45
|
||||
Amortization
of debt issuance costs and premium/discounts
|
1
|
1
|
||||
Deferred
income taxes and investment tax credits, net
|
(27
|
)
|
(5
|
)
|
||
Other
|
1
|
1
|
||||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
60
|
21
|
||||
Materials
and supplies
|
(7
|
)
|
(25
|
)
|
||
Accounts
and wages payable
|
(5
|
)
|
39
|
|||
Taxes
accrued
|
8
|
|
16
|
|||
Assets,
other
|
-
|
(32
|
)
|
|||
Liabilities,
other
|
-
|
41
|
||||
Pension
and other postretirement obligations, net
|
6
|
-
|
||||
Net
cash provided by operating activities
|
127
|
148
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(63
|
)
|
(41
|
)
|
||
Proceeds
from intercompany note receivable – Genco
|
34
|
52
|
||||
Changes
in money pool advances
|
(18
|
)
|
(51
|
)
|
||
Net
cash used in investing activities
|
(47
|
)
|
(40
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(50
|
)
|
(21
|
)
|
||
Dividends
on preferred stock
|
(2
|
)
|
(2
|
)
|
||
Capital
issuance costs
|
(1
|
)
|
-
|
|||
Changes
in money pool borrowings
|
(2
|
)
|
(68
|
)
|
||
Redemptions,
repurchases, and maturities:
|
||||||
Long-term
debt
|
(20
|
)
|
(20
|
)
|
||
Intercompany
note payable - UE
|
(67
|
)
|
-
|
|||
Issuance
of long-term debt
|
61
|
-
|
||||
Capital
contribution from parent
|
1
|
1
|
||||
Net
cash used in financing activities
|
(80
|
)
|
(110
|
)
|
||
Net
change in cash and cash equivalents
|
-
|
(2
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
-
|
2
|
||||
Cash
and cash equivalents at end of period
|
$
|
-
|
$
|
-
|
||
The
accompanying notes as they relate to CIPS are an integral part of
these financial statements.
16
AMEREN
ENERGY GENERATING COMPANY
|
||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
||||||||||||
(Unaudited)
(In millions)
|
||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
259
|
$
|
287
|
$
|
744
|
$
|
777
|
||||
Other
|
-
|
2
|
-
|
2
|
||||||||
Total
operating revenues
|
259
|
289
|
744
|
779
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
170
|
162
|
485
|
398
|
||||||||
Other
operations and maintenance
|
34
|
32
|
113
|
108
|
||||||||
Depreciation
and amortization
|
18
|
18
|
53
|
55
|
||||||||
Taxes
other than income taxes
|
3
|
4
|
14
|
7
|
||||||||
Total
operating expenses
|
225
|
216
|
665
|
568
|
||||||||
Operating
Income
|
34
|
73
|
79
|
211
|
||||||||
Other
Income:
|
||||||||||||
Miscellaneous
income
|
-
|
-
|
-
|
1
|
||||||||
Total
other income
|
-
|
-
|
-
|
1
|
||||||||
Interest
Charges
|
15
|
17
|
45
|
57
|
||||||||
Income
Before Income Taxes
|
19
|
56
|
34
|
155
|
||||||||
Income
Taxes
|
-
|
24
|
7
|
61
|
||||||||
Net
Income
|
$
|
19
|
$
|
32
|
$
|
27
|
$
|
94
|
||||
The
accompanying notes as they relate to Genco are an integral part of these
consolidated financial statements.
17
AMEREN
ENERGY GENERATING COMPANY
|
||||||
CONSOLIDATED
BALANCE SHEET
|
||||||
(Unaudited)
(In millions, except shares)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
2
|
$
|
-
|
||
Accounts
receivable – affiliates
|
143
|
102
|
||||
Accounts
receivable – trade
|
18
|
29
|
||||
Materials
and supplies
|
103
|
73
|
||||
Other
current assets
|
4
|
1
|
||||
Total
current assets
|
270
|
205
|
||||
Property
and Plant, Net
|
1,512
|
1,514
|
||||
Intangible
Assets
|
81
|
79
|
||||
Other
Assets
|
27
|
13
|
||||
TOTAL
ASSETS
|
$
|
1,890
|
$
|
1,811
|
||
LIABILITIES
AND STOCKHOLDER'S EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
portion of intercompany note payable – CIPS
|
$
|
37
|
$
|
34
|
||
Borrowings
from money pool
|
216
|
203
|
||||
Accounts
and wages payable
|
25
|
41
|
||||
Accounts
payable – affiliates
|
84
|
60
|
||||
Current
portion of intercompany tax payable – CIPS
|
10
|
10
|
||||
Taxes
accrued
|
24
|
37
|
||||
Other
current liabilities
|
32
|
16
|
||||
Total
current liabilities
|
428
|
401
|
||||
Long-term
Debt, Net
|
474
|
474
|
||||
Intercompany
Note Payable – CIPS
|
126
|
163
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes, net
|
161
|
156
|
||||
Accumulated
deferred investment tax credits
|
9
|
10
|
||||
Intercompany
tax payable – CIPS
|
118
|
125
|
||||
Asset
retirement obligations
|
30
|
29
|
||||
Accrued
pension and other postretirement benefits
|
12
|
8
|
||||
Other
deferred credits and liabilities
|
2
|
1
|
||||
Total
deferred credits and other liabilities
|
332
|
329
|
||||
Commitments
and Contingencies (Notes 2 and 8)
|
||||||
Stockholder's
Equity:
|
||||||
Common
stock, no par value, 10,000 shares authorized – 2,000 shares
outstanding
|
-
|
-
|
||||
Other
paid-in capital
|
378
|
228
|
||||
Retained
earnings
|
154
|
220
|
||||
Accumulated
other comprehensive loss
|
(2
|
)
|
(4
|
)
|
||
Total
stockholder's equity
|
530
|
444
|
||||
TOTAL
LIABILITIES AND STOCKHOLDER'S EQUITY
|
$
|
1,890
|
$
|
1,811
|
||
The
accompanying notes as they relate to Genco are an integral part of these
consolidated financial statements.
18
AMEREN
ENERGY GENERATING COMPANY
|
||||||
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
27
|
$
|
94
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
78
|
78
|
||||
Amortization
of debt issuance costs and discounts
|
-
|
1
|
||||
Deferred
income taxes and investment tax credits, net
|
7
|
35
|
||||
Gain
on sales of emission allowances
|
(1
|
)
|
(1
|
)
|
||
Other
|
1
|
(21
|
)
|
|||
Changes
in assets and liabilities:
|
||||||
Accounts
receivable
|
(30
|
)
|
(10
|
)
|
||
Materials
and supplies
|
(30
|
)
|
(8
|
)
|
||
Accounts
and wages payable
|
13
|
59
|
||||
Taxes
accrued, net
|
(9
|
)
|
(35
|
)
|
||
Assets,
other
|
(16
|
)
|
6
|
|||
Liabilities,
other
|
2
|
7
|
||||
Pension
and other postretirement benefit obligations, net
|
4
|
-
|
||||
Net
cash provided by operating activities
|
46
|
205
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(55
|
)
|
(52
|
)
|
||
Proceeds
from asset sale to UE
|
-
|
241
|
||||
Changes
in money pool advances
|
-
|
(65
|
)
|
|||
Purchases
of emission allowances
|
(26
|
)
|
(71
|
)
|
||
Sales
of emission allowances
|
1
|
1
|
||||
Net
cash provided by (used in) investing activities
|
(80
|
)
|
54
|
|||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(93
|
)
|
(59
|
)
|
||
Changes
in money pool borrowings
|
13
|
(116
|
)
|
|||
Repayment
of intercompany notes payable – CIPS and Ameren
|
(34
|
)
|
(86
|
)
|
||
Capital
contribution from parent
|
150
|
1
|
||||
Net
cash provided by (used in) financing activities
|
36
|
(260
|
)
|
|||
Net
change in cash and cash equivalents
|
2
|
(1
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
-
|
1
|
||||
Cash
and cash equivalents at end of period
|
$
|
2
|
$
|
-
|
||
The
accompanying notes as they relate to Genco are an integral part of these
consolidated financial statements.
19
CILCORP
INC.
|
||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
||||||||||||
(Unaudited)
(In millions)
|
||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
119
|
$
|
116
|
$
|
309
|
$
|
309
|
||||
Gas
|
38
|
41
|
236
|
215
|
||||||||
Other
|
1
|
2
|
1
|
4
|
||||||||
Total
operating revenues
|
158
|
159
|
546
|
528
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
43
|
54
|
104
|
126
|
||||||||
Gas
purchased for resale
|
24
|
27
|
175
|
150
|
||||||||
Other
operations and maintenance
|
41
|
41
|
130
|
122
|
||||||||
Depreciation
and amortization
|
18
|
18
|
59
|
54
|
||||||||
Taxes
other than income taxes
|
5
|
4
|
18
|
15
|
||||||||
Total
operating expenses
|
131
|
144
|
486
|
467
|
||||||||
Operating
Income
|
27
|
15
|
60
|
61
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
-
|
-
|
1
|
-
|
||||||||
Miscellaneous
expense
|
(2
|
)
|
(2
|
)
|
(4
|
)
|
(7
|
)
|
||||
Total
other expenses
|
(2
|
)
|
(2
|
)
|
(3
|
)
|
(7
|
)
|
||||
Interest
Charges
|
13
|
12
|
38
|
37
|
||||||||
Income
Before Income Taxes & Preferred
|
||||||||||||
Dividends
of Subsidiaries
|
12
|
1
|
19
|
17
|
||||||||
Income
Tax Benefit
|
(1
|
)
|
(5
|
)
|
(4
|
)
|
(1
|
)
|
||||
Income
Before Preferred Dividends of Subsidiaries
|
13
|
6
|
23
|
18
|
||||||||
Preferred
Dividends of Subsidiaries
|
-
|
1
|
1
|
2
|
||||||||
Net
Income
|
$
|
13
|
$
|
5
|
$
|
22
|
$
|
16
|
||||
The
accompanying notes as they relate to CILCORP are an integral part of these
consolidated financial statements.
20
CILCORP
INC.
|
||||||
CONSOLIDATED
BALANCE SHEET
|
||||||
(Unaudited)
(In millions, except shares)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
3
|
$
|
3
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $3 and $5, respectively)
|
35
|
61
|
||||
Unbilled
revenue
|
33
|
59
|
||||
Accounts
receivables – affiliates
|
21
|
18
|
||||
Note
receivable – Resources Company
|
-
|
42
|
||||
Materials
and supplies
|
107
|
85
|
||||
Other
current assets
|
34
|
50
|
||||
Total
current assets
|
233
|
318
|
||||
Property
and Plant, Net
|
1,218
|
1,212
|
||||
Investments
and Other Assets:
|
||||||
Investments
in leveraged leases
|
-
|
21
|
||||
Goodwill
|
575
|
575
|
||||
Intangible
assets
|
50
|
62
|
||||
Other
assets
|
16
|
35
|
||||
Regulatory
assets
|
12
|
11
|
||||
Total
investments and other assets
|
653
|
704
|
||||
TOTAL
ASSETS
|
$
|
2,104
|
$
|
2,234
|
||
LIABILITIES
AND STOCKHOLDER'S EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
50
|
$
|
-
|
||
Borrowings
from money pool
|
62
|
154
|
||||
Intercompany
note payable – Ameren
|
156
|
186
|
||||
Accounts
and wages payable
|
35
|
81
|
||||
Accounts
payable – affiliates
|
16
|
28
|
||||
Other
current liabilities
|
61
|
55
|
||||
Total
current liabilities
|
380
|
504
|
||||
Long-term
Debt, Net
|
584
|
534
|
||||
Preferred
Stock of Subsidiary Subject to Mandatory
Redemption
|
18
|
19
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes, net
|
159
|
163
|
||||
Accumulated
deferred investment tax credits
|
8
|
9
|
||||
Regulatory
liabilities
|
50
|
41
|
||||
Accrued
pension and other postretirement benefits
|
253
|
251
|
||||
Other
deferred credits and liabilities
|
17
|
31
|
||||
Total
deferred credits and other liabilities
|
487
|
495
|
||||
Preferred
Stock of Subsidiary Not Subject to Mandatory
Redemption
|
19
|
19
|
||||
Commitments
and Contingencies (Notes 2 and 8)
|
||||||
Stockholder's
Equity:
|
||||||
Common
stock, no par value, 10,000 shares authorized – 1,000 shares
outstanding
|
-
|
-
|
||||
Other
paid-in capital
|
598
|
640
|
||||
Retained
earnings
|
15
|
-
|
||||
Accumulated
other comprehensive income
|
3
|
23
|
||||
Total
stockholder's equity
|
616
|
663
|
||||
TOTAL
LIABILITIES AND STOCKHOLDER'S EQUITY
|
$
|
2,104
|
$
|
2,234
|
||
The
accompanying notes as they relate to CILCORP are an integral part of these
consolidated financial statements.
21
CILCORP
INC.
|
||||||
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
|
||||||
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
22
|
$
|
16
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
74
|
74
|
||||
Deferred
income taxes and investment tax credits
|
8
|
(19
|
)
|
|||
Loss
on sale of leveraged lease investments
|
4
|
-
|
||||
Gain
on sales of emission allowances
|
-
|
(1
|
)
|
|||
Other
|
1
|
1
|
||||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
49
|
20
|
||||
Materials
and supplies
|
(22
|
)
|
(17
|
)
|
||
Accounts
and wages payable
|
(52
|
)
|
(9
|
)
|
||
Taxes
accrued
|
(9
|
)
|
(8
|
)
|
||
Assets,
other
|
24
|
9
|
||||
Liabilities,
other
|
(4
|
)
|
9
|
|||
Pension
and postretirement benefit obligations, net
|
4
|
2
|
||||
Net
cash provided by operating activities
|
99
|
77
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(70
|
)
|
(71
|
)
|
||
Proceeds
from note receivable - Resources Company
|
42
|
-
|
||||
Proceeds
from sale of leveraged leases
|
11
|
-
|
||||
Purchases
of emissions allowances
|
(12
|
)
|
(21
|
)
|
||
Sales
of emission allowances
|
1
|
1
|
||||
Other
|
-
|
4
|
||||
Net
cash used in investing activities
|
(28
|
)
|
(87
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(50
|
)
|
(30
|
)
|
||
Capital
issuance costs
|
(2
|
)
|
-
|
|||
Changes
in money pool borrowings
|
(92
|
)
|
(85
|
)
|
||
Proceeds
(repayment) - intercompany note payable - Ameren
|
(30
|
)
|
28
|
|||
Borrowings
from credit facility
|
40
|
-
|
||||
Redemptions,
repurchases, and maturities:
|
||||||
Long-term
debt
|
(32
|
)
|
(6
|
)
|
||
Preferred
stock
|
(1
|
)
|
(1
|
)
|
||
Issuance
of long-term debt
|
96
|
-
|
||||
Capital
contribution from parent
|
-
|
101
|
||||
Net
cash provided by (used in) financing activities
|
(71
|
)
|
7
|
|||
Net
change in cash and cash equivalents
|
-
|
(3
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
3
|
7
|
||||
Cash
and cash equivalents at end of period
|
$
|
3
|
$
|
4
|
||
The
accompanying notes as they relate to CILCORP are an integral part of these
consolidated financial statements.
22
CENTRAL
ILLINOIS LIGHT COMPANY
|
||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
||||||||||||
(Unaudited)
(In millions)
|
||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
119
|
$
|
117
|
$
|
309
|
$
|
309
|
||||
Gas
|
38
|
41
|
236
|
212
|
||||||||
Other
|
-
|
1
|
1
|
1
|
||||||||
Total
operating revenues
|
157
|
159
|
546
|
522
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
39
|
49
|
95
|
117
|
||||||||
Gas
purchased for resale
|
24
|
27
|
175
|
146
|
||||||||
Other
operations and maintenance
|
41
|
44
|
134
|
128
|
||||||||
Depreciation
and amortization
|
18
|
17
|
52
|
50
|
||||||||
Taxes
other than income taxes
|
4
|
4
|
17
|
14
|
||||||||
Total
operating expenses
|
126
|
141
|
473
|
455
|
||||||||
Operating
Income
|
31
|
18
|
73
|
67
|
||||||||
Other
Expenses:
|
||||||||||||
Miscellaneous
expense
|
(2
|
)
|
(2
|
)
|
(4
|
)
|
(5
|
)
|
||||
Total
other expenses
|
(2
|
)
|
(2
|
)
|
(4
|
)
|
(5
|
)
|
||||
Interest
Charges
|
4
|
3
|
13
|
10
|
||||||||
Income
Before Income Taxes
|
25
|
13
|
56
|
52
|
||||||||
Income
Taxes
|
6
|
2
|
12
|
15
|
||||||||
Net
Income
|
19
|
11
|
44
|
37
|
||||||||
Preferred
Stock Dividends
|
-
|
1
|
1
|
2
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
19
|
$
|
10
|
$
|
43
|
$
|
35
|
||||
The
accompanying notes as they relate to CILCO are an integral part of these
consolidated financial statements.
23
CENTRAL
ILLINOIS LIGHT COMPANY
|
||||||
CONSOLIDATED
BALANCE SHEET
|
||||||
(Unaudited)
(In millions)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
2
|
$
|
2
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $3 and $5, respectively)
|
35
|
61
|
||||
Unbilled
revenue
|
33
|
59
|
||||
Accounts
receivable – affiliates
|
15
|
14
|
||||
Materials
and supplies
|
107
|
87
|
||||
Other
current assets
|
36
|
43
|
||||
Total
current assets
|
228
|
266
|
||||
Property
and Plant, Net
|
1,232
|
1,214
|
||||
Investments
in Leveraged Leases
|
-
|
21
|
||||
Intangible
Assets
|
4
|
4
|
||||
Other
Assets
|
22
|
41
|
||||
Regulatory
Assets
|
12
|
11
|
||||
TOTAL
ASSETS
|
$
|
1,498
|
$
|
1,557
|
||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
50
|
$
|
-
|
||
Borrowings
from money pool
|
62
|
161
|
||||
Accounts
and wages payable
|
35
|
81
|
||||
Accounts
payable – affiliates
|
31
|
26
|
||||
Other
current liabilities
|
46
|
48
|
||||
Total
current liabilities
|
224
|
316
|
||||
Long-term
Debt, Net
|
188
|
122
|
||||
Preferred
Stock Subject to Mandatory Redemption
|
18
|
19
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes, net
|
166
|
167
|
||||
Accumulated
deferred investment tax credits
|
8
|
8
|
||||
Regulatory
liabilities
|
201
|
187
|
||||
Accrued
pension and other postretirement benefits
|
155
|
146
|
||||
Other
deferred credits and liabilities
|
18
|
30
|
||||
Total
deferred credits and other liabilities
|
548
|
538
|
||||
Commitments
and Contingencies (Notes 2 and 8)
|
||||||
Stockholders'
Equity:
|
||||||
Common
stock, no par value, 20.0 shares authorized – 13.6 shares
outstanding
|
-
|
-
|
||||
Preferred
stock not subject to mandatory redemption
|
19
|
19
|
||||
Other
paid-in capital
|
414
|
415
|
||||
Retained
earnings
|
97
|
119
|
||||
Accumulated
other comprehensive income (loss)
|
(10
|
)
|
9
|
|||
Total
stockholders' equity
|
520
|
562
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
1,498
|
$
|
1,557
|
||
The
accompanying notes as they relate to CILCO are an integral part of these
consolidated financial statements.
24
CENTRAL
ILLINOIS LIGHT COMPANY
|
||||||
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
|
||||||
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
44
|
$
|
37
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
61
|
64
|
||||
Deferred
income taxes and investment tax credits
|
15
|
(5
|
)
|
|||
Loss
on sale of leveraged leases
|
6
|
-
|
||||
Gain
on sales of emission allowances
|
-
|
(1
|
)
|
|||
Other
|
-
|
6
|
||||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
51
|
30
|
||||
Materials
and supplies
|
(20
|
)
|
(15
|
)
|
||
Accounts
and wages payable
|
(35
|
)
|
-
|
|||
Taxes
accrued
|
(17
|
)
|
(17
|
)
|
||
Assets,
other
|
14
|
-
|
||||
Liabilities,
other
|
(6
|
)
|
(9
|
)
|
||
Pension
and postretirement benefit obligations, net
|
9
|
11
|
||||
Net
cash provided by operating activities
|
122
|
101
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(70
|
)
|
(71
|
)
|
||
Proceeds
from sale of leveraged leases
|
11
|
-
|
||||
Purchases
of emission allowances
|
(12
|
)
|
(21
|
)
|
||
Sales
of emission allowances
|
1
|
1
|
||||
Net
cash used in investing activities
|
(70
|
)
|
(91
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(65
|
)
|
(20
|
)
|
||
Dividends
on preferred stock
|
(1
|
)
|
(2
|
)
|
||
Capital
issuance costs
|
(2
|
)
|
-
|
|||
Changes
in money pool borrowings
|
(99
|
)
|
(88
|
)
|
||
Borrowings
from credit facility
|
40
|
-
|
||||
Redemptions,
repurchases, and maturities:
|
||||||
Long-term
debt
|
(20
|
)
|
-
|
|||
Preferred
stock
|
(1
|
)
|
(1
|
)
|
||
Issuance
of long-term debt
|
96
|
-
|
||||
Capital
contribution from parent
|
-
|
101
|
||||
Net
cash used in financing activities
|
(52
|
)
|
(10
|
)
|
||
Net
change in cash and cash equivalents
|
-
|
-
|
||||
Cash
and cash equivalents at beginning of year
|
2
|
2
|
||||
Cash
and cash equivalents at end of period
|
$
|
2
|
$
|
2
|
||
The
accompanying notes as they relate to CILCO are an integral part of these
consolidated financial statements.
25
ILLINOIS
POWER COMPANY
|
|||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
|||||||||||||
(Unaudited)
(In millions)
|
|||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
Operating
Revenues:
|
|||||||||||||
Electric
|
$
|
375
|
$
|
358
|
$
|
888
|
$
|
861
|
|||||
Gas
|
59
|
61
|
381
|
331
|
|||||||||
Other
|
1
|
1
|
2
|
1
|
|||||||||
Total
operating revenues
|
435
|
420
|
1,271
|
1,193
|
|||||||||
Operating
Expenses:
|
|||||||||||||
Purchased
power
|
213
|
187
|
561
|
509
|
|||||||||
Gas
purchased for resale
|
35
|
37
|
272
|
227
|
|||||||||
Other
operations and maintenance
|
68
|
64
|
188
|
166
|
|||||||||
Depreciation
and amortization
|
20
|
19
|
57
|
59
|
|||||||||
Taxes
other than income taxes
|
14
|
14
|
52
|
54
|
|||||||||
Total
operating expenses
|
350
|
321
|
1,130
|
1,015
|
|||||||||
Operating
Income
|
85
|
99
|
141
|
178
|
|||||||||
Other
Income and Expenses:
|
|||||||||||||
Miscellaneous
income
|
2
|
2
|
4
|
6
|
|||||||||
Miscellaneous
expense
|
(1
|
)
|
-
|
(3
|
)
|
(1
|
)
|
||||||
Total
other income
|
1
|
2
|
1
|
5
|
|||||||||
Interest
Charges
|
13
|
11
|
37
|
32
|
|||||||||
Income
Before Income Taxes
|
73
|
90
|
105
|
151
|
|||||||||
Income
Taxes
|
30
|
36
|
42
|
60
|
|||||||||
Net
Income
|
43
|
54
|
63
|
91
|
|||||||||
Preferred
Stock Dividends
|
1
|
1
|
2
|
2
|
|||||||||
Net
Income Available to Common Stockholder
|
$
|
42
|
$
|
53
|
$
|
61
|
$
|
89
|
|||||
The
accompanying notes as they relate to IP are an integral part of these
consolidated financial statements.
26
ILLINOIS
POWER COMPANY
|
||||||
CONSOLIDATED
BALANCE SHEET
|
||||||
(Unaudited)
(In millions)
|
||||||
September
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
-
|
$
|
-
|
||
Accounts
receivable - trade (less allowance for doubtful
|
||||||
accounts
of $3 and $8, respectively)
|
111
|
155
|
||||
Unbilled
revenue
|
82
|
118
|
||||
Accounts
receivable – affiliates
|
25
|
5
|
||||
Materials
and supplies
|
156
|
122
|
||||
Other
current assets
|
13
|
31
|
||||
Total
current assets
|
387
|
431
|
||||
Property
and Plant, Net
|
2,098
|
2,035
|
||||
Investments
and Other Assets:
|
||||||
Investment
in IP SPT
|
8
|
7
|
||||
Goodwill
|
326
|
326
|
||||
Other
assets
|
64
|
44
|
||||
Regulatory
assets
|
197
|
194
|
||||
Accumulated
deferred income taxes
|
-
|
19
|
||||
Total
investments and other assets
|
595
|
590
|
||||
TOTAL
ASSETS
|
$
|
3,080
|
$
|
3,056
|
||
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt to IP SPT
|
$
|
55
|
$
|
72
|
||
Borrowings
from money pool
|
110
|
75
|
||||
Accounts
and wages payable
|
95
|
145
|
||||
Accounts
payable – affiliates
|
14
|
29
|
||||
Taxes
accrued
|
13
|
15
|
||||
Other
current liabilities
|
97
|
135
|
||||
Total
current liabilities
|
384
|
471
|
||||
Long-term
Debt, Net
|
773
|
704
|
||||
Long-term
Debt to IP SPT
|
115
|
184
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Regulatory
liabilities
|
121
|
80
|
||||
Accrued
pension and other postretirement benefits
|
259
|
255
|
||||
Other
deferred credits and other noncurrent liabilities
|
81
|
75
|
||||
Total
deferred credits and other liabilities
|
461
|
410
|
||||
Commitments
and Contingencies (Notes 2 and 8)
|
||||||
Stockholders’
Equity:
|
||||||
Common
stock, no par value, 100.0 shares authorized – 23.0 shares outstanding
|
-
|
-
|
||||
Other
paid-in-capital
|
1,194
|
1,196
|
||||
Preferred
stock not subject to mandatory redemption
|
46
|
46
|
||||
Retained
earnings
|
108
|
46
|
||||
Accumulated
other comprehensive loss
|
(1
|
)
|
(1
|
)
|
||
Total
stockholders’ equity
|
1,347
|
1,287
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
3,080
|
$
|
3,056
|
||
The
accompanying notes as they relate to IP are an integral part of these
consolidated financial statements.
27
ILLINOIS
POWER COMPANY
|
||||||
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
||||||
(Unaudited)
(In millions)
|
||||||
Nine
Months Ended
|
||||||
September
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
63
|
$
|
91
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
|
18
|
31
|
|||
Amortization
of debt issuance costs and premium/discounts
|
3
|
2
|
||||
Deferred
income taxes
|
58
|
39
|
||||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
60
|
11
|
||||
Materials
and supplies
|
(34
|
)
|
(45
|
)
|
||
Accounts
and wages payable
|
(64
|
)
|
34
|
|||
Assets,
other
|
(1
|
)
|
25
|
|||
Liabilities,
other
|
(5
|
)
|
15
|
|||
Pension
and other postretirement benefit obligations, net
|
8
|
4
|
||||
Net
cash provided by operating activities
|
106
|
207
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(126
|
)
|
(95
|
)
|
||
Changes
in money pool advances
|
-
|
90
|
||||
Other
|
(1
|
)
|
1
|
|||
Net
cash used in investing activities
|
(127
|
)
|
(4
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
-
|
(60
|
)
|
|||
Dividends
on preferred stock
|
(2
|
)
|
(2
|
)
|
||
Capital
issuance costs
|
(1
|
)
|
-
|
|||
Changes
in money pool borrowings, net
|
35
|
-
|
||||
Redemptions
and repurchases of long-term debt
|
(69
|
)
|
(135
|
)
|
||
Issuances
of long-term debt
|
75
|
-
|
||||
Transitional
funding trust notes overfunding
|
(17
|
)
|
(6
|
)
|
||
Net
cash provided by (used in) financing activities
|
21
|
(203
|
)
|
|||
Net
change in cash and cash equivalents
|
-
|
-
|
||||
Cash
and cash equivalents at beginning of year
|
-
|
5
|
||||
Cash
and cash equivalents at end of period
|
$
|
-
|
$
|
5
|
||
The
accompanying notes as they relate to IP are an integral part of these
consolidated financial statements.
28
AMEREN
CORPORATION (Consolidated)
UNION
ELECTRIC COMPANY (Consolidated)
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
AMEREN
ENERGY GENERATING COMPANY (Consolidated)
CILCORP
INC. (Consolidated)
CENTRAL
ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS
POWER COMPANY (Consolidated)
COMBINED
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
September
30, 2006
NOTE
1 - SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren,
headquartered in St. Louis, Missouri, is a public utility holding company under
PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public
utility holding company under PUHCA 1935 until that act was repealed effective
February 8, 2006. Ameren’s primary asset is the common stock of its
subsidiaries. Ameren’s subsidiaries, which are separate, independent legal
entities with separate businesses, assets and liabilities, operate
rate-regulated electric generation, transmission and distribution businesses,
rate-regulated natural gas transmission and distribution businesses and
non-rate-regulated electric generation businesses in Missouri and Illinois,
as
discussed below. Dividends on Ameren’s common stock depend on distributions made
to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.
Also see the Glossary of Terms and Abbreviations at the front of this
report.
· |
UE,
or Union Electric Company, also known as AmerenUE, operates a
rate-regulated electric generation, transmission and distribution
business, and a rate-regulated natural gas transmission and distribution
business in Missouri.
|
· |
CIPS,
or Central Illinois Public Service Company, also known as AmerenCIPS,
operates a rate-regulated electric and natural gas transmission and
distribution business in Illinois.
|
· |
Genco,
or Ameren Energy Generating Company, operates a non-rate-regulated
electric generation business in Illinois and Missouri.
|
· |
CILCO,
or Central Illinois Light Company, also known as AmerenCILCO, is
a
subsidiary of CILCORP (a holding company). It operates a rate-regulated
electric transmission and distribution business, a primarily
non-rate-regulated electric generation business (through its subsidiary
AERG), and a rate-regulated natural gas transmission and distribution
business in Illinois.
|
· |
IP,
or Illinois Power Company, also known as AmerenIP, operates a
rate-regulated electric and natural gas transmission and distribution
business in Illinois.
|
Ameren
has various other subsidiaries responsible for the short- and long-term
marketing of power, procurement of fuel, management of commodity risks, and
provision of other shared services. Ameren has an 80% ownership interest in
EEI
through UE and Development Company, which each own 40% of EEI. Ameren
consolidates EEI for financial reporting purposes, while UE reports EEI under
the equity method. The following table presents summarized financial information
of EEI (in millions) for the three months and nine months ended September 30,
2006 and 2005.
Three
Months
|
Nine
Months
|
|
||||||||||
|
|
2006
|
|
|
2005
|
|
|
2006
|
2005
|
|||
Operating
revenues
|
$
|
105
|
$
|
43
|
$
|
290
|
$
|
127
|
||||
Operating
income
|
93
|
4
|
191
|
15
|
||||||||
Net
income
|
56
|
3
|
117
|
8
|
The
financial statements of the Ameren Companies (except CIPS) are prepared on
a
consolidated basis and therefore include the accounts of their majority-owned
subsidiaries, as applicable. All significant intercompany transactions have
been
eliminated. All tabular dollar amounts are in millions, unless otherwise
indicated.
Our
accounting policies conform to GAAP. Our financial statements reflect all
adjustments (which include normal, recurring adjustments) necessary, in our
opinion, for a fair presentation of our results. The preparation of financial
statements in conformity with GAAP requires management to make certain estimates
and assumptions. Such estimates and assumptions affect reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities
at
the dates of financial statements, and the reported amounts of revenues and
expenses during the reported periods. Actual results could differ from those
estimates. The results of operations of an interim period may not give a true
indication of results for a full year. Certain reclassifications have been
made
to make prior period financial statements conform to 2006 reporting, including
the reclassification of emission allowance purchases and sales from Operating
Activities to Investing Activities on the Statements of Cash Flows for Ameren,
UE, Genco, CILCORP and CILCO. These financial statements should be read in
conjunction with the financial statements and the notes thereto included in
the
Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended
December 31, 2005. In the third quarter of 2006, Ameren, UE, CILCORP and CILCO
changed their reportable segments. See further discussion in Note 12 - Segment
Information.
Earnings
Per Share
There
were no material differences between Ameren’s basic and diluted earnings per
share amounts for the three months and nine months ended September 30, 2006
and
2005, due to an immaterial number of stock options, restricted stock units
and
performance share units outstanding.
29
Accounting
Changes and Other Matters
SFAS
No. 123 (revised 2004), Share-based
Payment
Effective
January 1, 2003, Ameren adopted the fair value recognition provisions of SFAS
No. 123, “Accounting for Stock-based Compensation” (SFAS 123), by using the
prospective method of adoption under SFAS No. 148, “Accounting for Stock-based
Compensation - Transition and Disclosure,” for all employee awards granted or
with terms modified on or after January 1, 2003.
Effective
January 1, 2006, Ameren adopted SFAS No. 123 (revised 2004) “Share-based
Payment” (SFAS 123R), which revises SFAS 123 and supersedes APB Opinion No. 25,
“Accounting for Stock Issued to Employees.” SFAS 123R requires companies to
measure the cost of employee services received in exchange for an award of
equity instruments by the grant-date fair value of the award. Ameren adopted
SFAS 123R utilizing the modified prospective application. Under the modified
prospective approach, SFAS 123R applies to all awards granted or modified after
the effective date.
Long-term
Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation
Plan
In
the
first quarter of 2006, Ameren’s Board of Directors approved the 2006 Omnibus
Incentive Compensation Plan (2006 Plan), subject to shareholder approval, which
was obtained on May 2, 2006. The 2006 Plan prospectively replaced the Long-term
Incentive Plan of 1998, as amended (1998 Plan), effective May 2, 2006. The
2006
Plan provides for a maximum number of 4,000,000 common shares available for
grant to eligible employees and directors. No new awards may be granted under
the 1998 Plan; however, previously granted awards continue to vest or be
exercisable in accordance with their original terms and conditions. The 2006
Plan awards may be stock options, stock appreciation rights, restricted stock,
restricted stock units, performance shares, performance share units, cash-based
awards, and other stock-based awards.
A
summary
of nonvested shares as of September 30, 2006, and changes during the nine-month
period ended September 30, 2006, under the 1998 Plan and the 2006 Plan is
presented below:
Performance
Share Units
|
Restricted
Shares
|
|||||||||||
Shares
|
Weighted-average
Fair Value Per Unit
|
Shares
|
Weighted-average
Fair Value Per Share
|
|||||||||
Nonvested
at January 1, 2006
|
-
|
$
|
-
|
575,469
|
$
|
44.91
|
||||||
Granted(a)
|
350,640
|
56.07
|
-
|
-
|
||||||||
Dividends
|
-
|
-
|
13,538
|
51.29
|
||||||||
Forfeitures
|
(881
|
)
|
56.07
|
(2,436
|
)
|
47.58
|
||||||
Vested(b)
|
(4,785
|
)
|
56.07
|
(213,198
|
)
|
43.38
|
||||||
Nonvested
at September 30, 2006
|
344,974
|
$
|
56.07
|
373,373
|
$
|
45.79
|
(a) |
Includes
220,434 performance share units (share units) granted to certain
executive
and non-executive officers and other eligible employees in February
2006
under the 1998 Plan and 130,206 share units granted in February 2006
under
the 2006 Plan to certain executive officers subject to shareholder
approval, which was obtained on May 2, 2006. The share units granted
under
the 2006 Plan were not considered as granted until approved by
shareholders. Accordingly, compensation expense recognition for these
awards commenced in May 2006.
|
(b) |
Share
units issued under the 1998 Plan vested due to the death of an employee
and attainment of retirement eligibility by certain employees. Actual
shares issued for retirement-eligible employees will vary depending
on
actual performance over the three-year measurement
period.
|
A
share
unit will vest and entitle an employee to receive shares of Ameren common stock
(plus accumulated dividends) if, at the end of the three-year performance
period, Ameren has achieved certain performance goals and the individual remains
employed by Ameren. The exact number of shares issued pursuant to a share unit
will vary from 0% to 200% of the target award depending on actual company
performance relative to the performance goals. If a share unit vests, Ameren
will issue the related shares to the employee two years after vesting, but
dividends on the shares will be paid to the employee at the same time they
are
paid to other shareholders.
The
fair
value of each share unit awarded in February 2006 under the 1998 Plan was
determined to be $56.07 based on Ameren’s closing common share price of $50.69
per share at the grant date and lattice simulations utilized to estimate
expected share payout based on Ameren’s attainment of certain financial measures
relative to the designated peer group. The significant assumptions utilized
to
calculate fair value also included a three-year risk-free rate of 4.65%,
dividend yields ranging from 2.3% to 4.6% for the peer group, volatility ranging
from 13.87% to 22.45% for the peer group, and Ameren’s maintenance of its $2.54
annual dividend over the performance period. The fair value of each share unit
granted in May 2006 under the 2006 Plan was determined to be $56.07 based on
assumptions similar to the February 2006 grant.
Ameren
recorded compensation expense of $3 million and $1 million for the quarters
ended September 30, 2006 and 2005, respectively, and a related tax benefit
of
less than $1 million for the quarters ended September 30, 2006 and 2005. Ameren
recorded compensation expense of $8 million and $5 million for each of the
nine-month periods ended September 30, 2006 and 2005, respectively, and a
related tax
30
benefit
of $1 million and $2 million for the nine-month periods ended September 30,
2006
and 2005, respectively. As of September 30, 2006, total compensation cost of
$21
million related to nonvested awards not yet recognized is expected to be
recognized over a weighted-average period of 3 years.
Ameren
has not granted any stock options subsequent to its adoption of SFAS 123, and
the options granted prior to the SFAS 123 adoption were fully expensed during
2004. Therefore, there is no expense from stock options for the three- and
nine-month periods ended September 30, 2006, and there is no pro forma expense
for the year-ago periods. See Note 1 - Summary of Significant Accounting
Policies and Note 12 - Stock-based Compensation in the Ameren Companies’
combined Annual Report on Form 10-K for the fiscal year ended December 31,
2005,
for additional information.
FASB
Interpretation No. 48, Accounting
for Uncertainty in Income Taxes (FIN
48)
FIN
48
establishes that the financial statement effects of a tax position taken or
expected to be taken in a tax return are to be recognized in the financial
statements when it is more likely than not, based on the technical merits,
that
the position will be sustained upon examination. In addition, FIN 48 requires
expanded disclosure with respect to the uncertainty in income taxes and is
effective as of the beginning of our 2007 fiscal year. We are still in the
process of determining the impact the adoption of FIN 48 will have on our
results of operations, financial position and liquidity; however, at this time,
we do not expect the impact of adoption to be material.
SFAS
No. 157, Fair
Value Measurements
In
September 2006, the FASB issued SFAS No. 157, which defines fair value,
establishes a framework for measuring fair value, and expands disclosures about
fair value measurements. SFAS No. 157 clarifies that fair value is a
market-based measurement that should be determined based on the assumptions
that
market participants would use in pricing an asset or liability. This standard
is
effective for Ameren as of the beginning of our 2008 fiscal year. We are still
in the process of determining the impact the adoption of SFAS No. 157 will
have
on our results of operations, financial position and liquidity, if any; however,
at this time, we do not expect the impact of adoption to be
material.
SFAS
No. 158, Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106 and
132(R)
In
September 2006, the FASB issued SFAS No. 158 requiring employers to recognize
the overfunded or underfunded positions of defined benefit postretirement plans,
including pension plans, as an asset or liability in their balance sheets and
to
recognize as a component of OCI, net of tax, the gains or losses and prior
service costs or credits that arise during the period but are not recognized
as
components of net periodic benefit cost. SFAS No. 158 also requires additional
disclosures in the notes to the financial statements. The recognition and
disclosure provisions of SFAS No. 158 are effective for Ameren as of December
31, 2006.
We
are in
the process of determining the impact the adoption of SFAS No. 158 will have
on
our financial position. However, based on the funded status of Ameren’s defined
benefit postretirement plans as of December 31, 2005, the Ameren Companies
would
be required to recognize additional pension and other postretirement benefit
obligations and write-off a pension-related intangible asset resulting in a
charge to OCI. The following table presents the amounts that would have been
recognized by the Ameren Companies as of December 31, 2005.
Pension
Benefit
Obligations
|
Postretirement
Benefit
Obligations
|
Intangible
Asset
|
|||||||
Ameren
|
$
|
234
|
$
|
308
|
$
|
(79
|
)
|
||
UE
|
150
|
197
|
(51
|
)
|
|||||
CIPS
|
23
|
31
|
(8
|
)
|
|||||
Genco
|
23
|
31
|
(8
|
)
|
|||||
CILCORP
|
21
|
28
|
(7
|
)
|
|||||
CILCO
|
21
|
28
|
(7
|
)
|
|||||
IP
|
17
|
21
|
(5
|
)
|
The
Ameren Companies will also be required to record a deferred tax benefit
associated with the temporary differences between the liabilities recognized
for
book and tax purposes. In addition, to the extent Ameren determines that it
is probable that some of the additional liabilities will be recoverable through
rates charged by Ameren’s rate-regulated businesses (UE, CIPS, CILCO and IP), a
regulatory asset may be recorded. The net result of increases and decreases
to
pension and other postretirement liabilities and assets, and the recognition
of
related deferred tax and regulatory assets will result in a charge to OCI and
a
decrease to common equity. The ultimate amounts recorded are highly dependent
on
a number of assumptions, including the discount rates in effect at December
31,
2006, the actual rate of return on our pension assets for 2006 and the tax
effects of the adjustment. Changes in these assumptions since our last
measurement date could increase or decrease the expected impact of implementing
SFAS No. 158 in our consolidated financial statements at December 31,
2006.
Staff
Accounting Bulletin No. 108, Considering
the Effects of Prior Year Misstatements When Quantifying Misstatements in
Current Year Financial Statements
(SAB 108)
In
September 2006, the SEC staff issued SAB 108 requiring public companies to
utilize a dual approach to assess the quantitative effects of financial
misstatements. The dual approach includes both an income statement-focused
31
assessment
and a balance sheet-focused assessment. SAB 108 is effective as of December
31,
2006, for errors that were not previously deemed material but are material
under
the guidance in SAB 108. While we are still in the process of determining the
impact the adoption of SAB 108 will have on our results of operations, financial
position and liquidity, we expect UE will make a pretax adjustment to increase
its beginning retained earnings balance by $12 million and CIPS will make an
adjustment to decrease its beginning retained earnings balance by $12 million.
The adoption of SAB 108 will not have an impact on Ameren and we do not expect
the adoption to have a material impact on the results of operations, financial
position and liquidity of any of the Ameren Companies.
Revenue
Interchange
Revenues
The
following table presents the interchange revenues included in Operating Revenues
- Electric for the three months and nine months ended September 30, 2006 and
2005. See Note 7 - Related Party Transactions for further information on
affiliate interchange revenues.
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren(a)
|
$
|
183
|
$
|
105
|
$
|
533
|
$
|
359
|
||||
UE
|
90
|
110
|
331
|
336
|
||||||||
CIPS
|
-
|
9
|
2
|
26
|
||||||||
Genco
|
39
|
56
|
129
|
165
|
||||||||
CILCORP
|
4
|
-
|
23
|
26
|
||||||||
CILCO
|
4
|
-
|
23
|
26
|
||||||||
IP
|
-
|
-
|
-
|
(b
|
)
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations. Includes interchange revenues at Marketing
Company and EEI of $103 million and $277 million for the three months
and
nine months ended September 30, 2006, respectively (2005 - $9 million
and
$24 million, respectively).
|
(b) |
Less
than $1 million.
|
Purchased
Power
The
following table presents the purchased power expenses included in Operating
Expenses - Fuel and Purchased Power for the three months and nine months ended
September 30, 2006 and 2005. See Note 7 - Related Party Transactions for further
information on affiliate purchased power transactions.
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren(a)
|
$
|
346
|
$
|
340
|
$
|
896
|
$
|
782
|
||||
UE
|
64
|
102
|
199
|
206
|
||||||||
CIPS
|
125
|
140
|
355
|
331
|
||||||||
Genco
|
84
|
89
|
269
|
206
|
||||||||
CILCORP
|
17
|
24
|
25
|
46
|
||||||||
CILCO
|
17
|
24
|
25
|
46
|
||||||||
IP
|
213
|
187
|
561
|
509
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations. Includes purchased power for EEI of $1
million
and $4 million for the three months and nine months ended September
30,
2006, respectively (2005 - nil and $1 million, respectively).
|
Excise
Taxes
Excise
taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer
bills are imposed on us. They are recorded gross in Operating Revenues and
Taxes
Other than Income Taxes on each company’s statement of income. Excise taxes
reflected on Illinois electric customer bills are imposed on the consumer and
are therefore not included in our revenues and expenses. They are recorded
as
tax collections payable and included in Other Current Liabilities. The following
table presents excise taxes recorded in Operating Revenues and Taxes Other
than
Income Taxes for the three months and nine months ended September 30, 2006
and
2005:
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren
|
$
|
43
|
$
|
44
|
$
|
129
|
$
|
125
|
||||
UE
|
35
|
35
|
87
|
84
|
||||||||
CIPS
|
2
|
3
|
11
|
10
|
||||||||
CILCORP
|
2
|
1
|
8
|
7
|
||||||||
CILCO
|
2
|
1
|
8
|
7
|
||||||||
IP
|
4
|
5
|
23
|
24
|
Asset
Retirement Obligations
AROs
at
Ameren and UE increased compared to December 31, 2005 to reflect the accretion
of obligations to their fair values.
NOTE
2 - RATE
AND REGULATORY MATTERS
Below
is
a summary of significant regulatory proceedings. We are unable to predict
the ultimate outcome of these regulatory proceedings, the timing of the
final decisions of the various agencies, or the impact on our results of
operations, financial position, or liquidity.
Missouri
Electric
With
the
expiration of an electric rate moratorium that provided for no changes in UE’s
electric rates before July 1, 2006, UE filed in July 2006 a request with the
MoPSC for an increase in base rates for electric service. UE’s filing included a
proposed average increase in electric rates of 17.7%, or $361 million. UE is
proposing to limit the increase on residential rates to 10%, allocating
requested revenue amounts above that level to other customer classes. This
rate
increase filing was based on a test year ended June 30, 2006, and included
known
and measurable items through January 1, 2007. Since UE’s last electric rate case
in 2002, UE has invested approximately $2.5 billion in its electric operations.
Those investments included more than $700 million for 2,600 megawatts of new
generation to meet growing customer power demands. UE’s electric rate request
includes, among other items, the following features:
32
· |
a
requested return on equity of 12%, and a rate base of $5.8 billion
with a
capital structure including about 52% common
equity;
|
· |
a
request for fuel, purchased power, and environmental cost recovery
mechanisms under the provisions of a Missouri state law enacted in
2005
(See MoPSC Rulemaking Proceeding below in this Note for additional
information);
|
· |
a
proposed alternative mechanism for the MoPSC’s consideration to share
off-system sales margins with
ratepayers;
|
· |
an
increase in depreciation rates;
|
· |
renewable
energy proposals, including the addition of 100 megawatts of renewable
energy by 2010;
|
· |
commitments
to offer low income energy assistance and energy conservation programs;
and
|
· |
costs
incurred related to the December 2005 failure of UE’s Taum Sauk
pumped-storage hydroelectric plant for the clean-up of a nearby park,
reimbursement of state costs and resolution of individuals’ claims were
excluded from the revenue increase
request.
|
The
MoPSC
staff and other stakeholders will review UE’s rate adjustment request and, after
their analyses, may also make recommendations as to electric rate adjustments.
A
decision from the MoPSC is expected no later than June 2007.
Gas
In
July
2006, UE filed a request with the MoPSC for an $11 million increase in natural
gas delivery rates, based on an 11.5% return on equity, and a rate base of
$200
million with a capital structure including about 52% common equity. The MoPSC
staff and other stakeholders will review UE’s rate adjustment request and, after
their analyses, may also make recommendations as to gas rate adjustments. A
decision from the MoPSC is expected no later than June 2007.
MoPSC
Rulemaking Proceeding
In
July
2005, a new law was enacted that enables the MoPSC to put in place fuel,
purchased power, and environmental cost recovery mechanisms for Missouri’s
utilities. The law also includes rate case filing requirements, a 2.5% annual
rate increase cap for the environmental cost recovery mechanism and prudency
reviews, among other things. Rules for the fuel and purchased power cost
recovery mechanism were approved by the MoPSC on September 21, 2006, and are
expected to be effective by the end of the year. We are unable to predict when
rules implementing the environmental cost recovery mechanism will be formally
proposed and adopted. UE requested fuel, purchased power and environmental
cost
recovery mechanisms in its electric rate case filed with the MoPSC in July
2006.
UE’s requests are subject to approval by the MoPSC.
Illinois
Electric
By
2002,
the power market for Illinois residential, commercial and industrial customers
of UE (whose Illinois utility business was transferred to CIPS in 2005), CIPS,
CILCO and IP was opened to alternative electric suppliers under the Illinois
Customer Choice Law. Under
the
Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen
through January 1, 2005. An
amendment to the Illinois Customer Choice Law extended the rate freeze through
January 1, 2007, with the consent of the Illinois utilities. As a result of
this
extension, and pursuant to ICC orders, CIPS and Marketing Company extended
their
power supply agreements through December 31, 2006, as did CILCO and
AERG.
As part
of Ameren’s acquisition of IP, IP entered into a power supply agreement with
DYPM to supply about 70% of its electric customer requirements through the
end
of 2006. The remaining 30% of IP’s power needs are being supplied by other
companies through contracts and open market purchases. See Note 7 - Related
Party Transactions for a discussion of the affiliate power supply agreements.
The following is a discussion of the current status of significant matters
affecting our Illinois electric operations post-2006.
Illinois
Power Procurement
During
2004, the ICC conducted workshops to seek input from interested parties on
the
framework for retail electric rate determination and power procurement after
the
Illinois electric rate freeze expires on January 1, 2007, and supply contracts
expire on December 31, 2006.
In
February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for
power procurement through an ICC-monitored auction, including, among other
things, a rate mechanism to pass power supply costs directly through to
customers. The form of power supply would meet the full requirements of each
utility, and the risk of fluctuations in power supply requirements would be
borne by the supplier. On January 24, 2006, the ICC issued an order that
unanimously approved the Ameren Illinois utilities’ proposed power procurement
auction and the related tariffs for the period commencing January 2, 2007,
including the retail rates by which power supply costs would be passed through
to customers. The order included the following key findings and
provisions:
· |
the
auction proposal is reasonably designed to enable CIPS, CILCO and
IP to
procure power supply in a competitive and least-cost
manner;
|
33
· |
there
is a limitation of 35% on the amount of power any single supplier
can
provide the Ameren Illinois utilities’ expected annual load.
Ameren-affiliated companies are considered one supplier for purposes
of
this limitation;
|
· |
requires
a portfolio of one-, two-, and three-year supply
contracts;
|
· |
allows
full cost recovery through a rate mechanism;
and
|
· |
requires
an annual, postauction prudence review by the
ICC.
|
In
accordance with the January 2006 ICC order, the power procurement auction was
held at the beginning of September 2006. On September 14, 2006, the ICC
determined that it would not investigate the results of the auction to procure
power for fixed-price customers, which include the vast majority of electric
customers of CIPS, CILCO and IP. On September 15, 2006, the independent auction
manager (NERA Economic Consulting) declared a successful result in the auction
for fixed-price customers. The auction clearing price was approximately $65
per
megawatthour for the fixed-price residential and small commercial product and
approximately $85 per megawatthour for large commercial and industrial
customers. Marketing Company was awarded sales in the auction. As a result
of
the large commercial and industrial customers’ auction price, it is expected
that nearly all of these customers will choose a different
supplier.
Certain
Illinois legislators, the Illinois attorney general, the Illinois governor
and
other parties sought to block the power procurement auction and continue to
challenge the auction and/or the recovery of costs for power supply resulting
from the auction through rates to customers. Opponents of the power procurement
auction and related tariffs claim that the ICC did not have authority to approve
market-based rates for electric service that have not been declared
“competitive” pursuant to Section 16-113 of the Illinois Public Utilities Act.
Opponents have claimed that the energy component of CIPS’, CILCO’s and IP’s
retail rates for electricity should not be based on the costs to procure energy
and capacity in the wholesale market. CIPS, CILCO and IP have received favorable
rulings from the ICC and the Circuit Court of Cook County, Illinois on
opposition claims filed by the Illinois attorney general, CUB and
ELPC.
Various
parties, including CIPS, CILCO, IP, the Illinois attorney general, CUB and
ELPC,
have filed appeals with Illinois district appellate courts of the ICC’s denial
of rehearing requests with respect to its January 2006 order. While CIPS, CILCO
and IP are generally supportive of the ICC order, they filed a request for
rehearing with regard to the provision of the January 2006 order requiring
an
annual, postauction prudence review to be performed by the ICC and in February
2006 appealed the ICC’s denial of the request to the appellate court for the
Fourth District in Illinois. CIPS, CILCO and IP asserted in their request for
rehearing that there is no basis for such a prudence review. In their requests
for rehearing of the January 2006 ICC order and their appeals of the ICC’s
denial of their requests filed with the First District Illinois appellate court
in March and April 2006, the Illinois attorney general, CUB and ELPC assert
that
the Ameren Illinois utilities power procurement auction should be dismissed
on
the basis of arguments generally similar to those that they previously raised
as
discussed above. In June 2006, the Illinois attorney general filed a petition
with the Supreme Court of Illinois seeking a direct and expedited review of
appeals filed with Illinois district courts by various parties of the ICC’s
January 2006 order approving the Illinois power procurement auction and a stay
on implementation of the order. In this petition, the Illinois attorney general
raised similar arguments to those previously raised as discussed above. In
August 2006, the Supreme Court of Illinois denied the Illinois attorney
general’s petition and ordered that the appeals be consolidated in the appellate
court for the Second District in Illinois. These appeals are
pending.
Delivery
Service Rate Cases
CIPS,
CILCO and IP filed rate cases with the ICC in December 2005 to modify their
electric delivery service rates effective January 2, 2007. CIPS, CILCO and
IP
requested to increase their annual revenues for electric delivery service
by
$202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and
IP -
$145 million). Since most customers are currently taking service
under a frozen bundled electric rate, which includes the cost of power, any
delivery service revenue change may not directly correspond to a change in
CIPS’, CILCO’s or IP’s revenues or earnings when all customers transition to an
electric delivery service rate effective January 2, 2007. To mitigate the
impact
of these requested increases on residential customers, CILCO and IP proposed
a
two-year phase-in with increases for average residential delivery rates capped
in the first year. The phase-in would decrease requested rate increases by
$10
million and $36 million for CILCO and IP, respectively, in the first year.
In
June 2006, the ICC staff filed rebuttal testimony recommending increases
in
revenues for electric delivery services for the Ameren Illinois utilities
aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP -
$89
million). In testimony, the Illinois attorney general accepted certain of
the
Ameren Illinois utilities’ positions, increasing its estimated aggregate
recommended revenue increase from $70 million to approximately $110
million (CIPS
- $3
million decrease, CILCO - $29 million increase and IP - $84 million
increase). Other parties also made recommendations in the cases. In October
2006, the administrative law judges issued a proposed order, which included
a
recommended revenue increase for electric delivery service of $147 million
in
the aggregate (CIPS - $8 million, CILCO - $29 million and
IP
- $110
million). The ICC has until November 25, 2006, to render a decision in these
cases.
34
Rate
Freeze Extension Proposal
In
February 2006, legislation was introduced in the Illinois House of
Representatives that would extend the electric rate freeze in Illinois through
2010. On October 2, 2006, Speaker of the Illinois House of Representatives,
Michael Madigan, sent a letter to Illinois Governor Rod Blagojevich asking
the
Illinois governor to call a special session of the Illinois General Assembly
for
the purpose of considering this rate freeze legislation. In response, the
Illinois governor sent a letter indicating that once the votes to pass the
legislation were in place he would immediately call for a special session of
the
legislature. The governor’s letter further provided that in the event a
consensus among members of the General Assembly is not reached in the near
future, he would call a special session in that event as well. The governor’s
letter stated he continued to support legislation extending a rate freeze and
would like to sign it into law as soon as possible. Copies of the speaker’s and
governor’s letters appear as Exhibits 99.1 and 99.2, respectively, to the
Current Report on Form 8-K dated October 4, 2006. On October 9, 2006, the
Electric Utility Oversight Committee of the Illinois House of Representatives
voted in favor of extending the electric rate freeze through 2010. The measure
will need to be approved by the full Illinois House of Representatives and
Illinois Senate, and signed by the Illinois governor before it could become
law.
CIPS,
CILCORP, CILCO and IP believe the proposed electric rate freeze legislation,
if
enacted, would have a material adverse effect on their results of operations,
financial position and liquidity, including the financial insolvency of CIPS,
CILCORP, CILCO and IP, as well as result in significant job losses and, without
governmental intervention, significant disruptions in electric and gas service.
Since Ameren’s Illinois utilities own almost no generation, the companies must
purchase power from the competitive market to provide customers’ energy needs.
If the rate freeze were extended, the Ameren Illinois utilities estimate they
would spend in the aggregate approximately $1 billion annually more for power
than they could charge their customers (CIPS - $415 million, CILCO - $175
million, IP - $410 million). It is likely that the Ameren Illinois utilities’
credit ratings would be downgraded to deep junk status if rate freeze
legislation was enacted. Moody's has also indicated that upon rate freeze
legislation, or similar legislation that restricts the recovery of costs in
a
timely manner, passing the Illinois House of Representatives (even if prior
to
passage in the Illinois Senate or enactment into law), it may consider
additional credit ratings downgrades with regard to one or more of the Ameren
Companies. With such credit ratings, we believe CIPS, CILCORP, CILCO and
IP would be faced with potential collateral and prepayment requirements for
products and services, such as power and natural gas, and would quickly run
out
of cash and available credit and be unable to borrow. We believe this would
lead
to the Ameren Illinois utilities and CILCORP being financially insolvent by
February 2007, or sooner. In reaction to intensified political discussion in
Illinois regarding electric rate freeze extension legislation, in October 2006
S&P downgraded the short- and long-term credit ratings of the Ameren
Companies and kept the Ameren Companies on credit watch with negative
implications; Moody’s placed the long-term debt credit ratings of the Ameren
Companies under review for possible downgrade; and Fitch placed the ratings
of
Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.
Electric
Rate Increase Phase-in Plans
CIPS,
CILCO and IP strongly believe that an extension of the electric rate freeze
in
Illinois would not be in the best interests of any of the Ameren Illinois
utilities or their customers and have been working with key stakeholders in
Illinois to develop a constructive rate increase phase-in plan for residential
and small to mid-size commercial customers to address the significant increases
in customer rates for the Ameren Illinois utilities beginning in 2007. The
Ameren Illinois utilities believe that a rate increase phase-in plan would
need
to allow for full and timely recovery of all deferred costs in a manner that
supports investment-grade credit ratings for CIPS, CILCO and IP.
CIPS,
CILCO and IP filed two proposed plans with the ICC to mitigate the impact of
expected higher electric rates for residential customers. The Customer Elect
Payment Plan (the Opt-In Plan), which these Ameren Illinois utilities filed
with
the ICC in October 2006, would allow residential customers the choice on an
individual basis to either pay the full amount of higher electricity costs
in
2007 or to phase in increases over a period of years. Under this plan, increases
would be phased in at an annual maximum increase of 15 percent over three years
or until the full amount of the rate increase is reached, whichever is earlier.
At the end of the phase-in period, customers would have three years to repay
the
deferred costs at a carrying charge interest rate of 6.5 percent. As part of
this filing, CIPS, CILCO and IP have proposed to make an additional contribution
of $5 million to their Dollar More and Warm Neighbors programs, which provide
bill paying assistance, energy conservation materials and rebates for energy
efficient equipment if this plan is approved.
Earlier
in 2006, the Ameren Illinois utilities filed with the ICC a rate increase
phase-in and revenue securitization plan for residential customers for the
deferral of power supply costs for 2007 and 2008. Unlike the Opt-In Plan,
legislation would be needed for this plan to become effective, and the plan
would apply to all residential customers (i.e. participation would not be
voluntary). In July 2006, the Illinois attorney general filed a motion with
the
ICC to dismiss this plan. In July 2006, the administrative law judge denied
the
Illinois attorney general’s motion. In March 2006, legislation was introduced in
the Illinois House of Representatives that would allow the
35
deferral
of a portion of the power procurement costs and would authorize the ICC to
permit a utility with fewer than one million retail customers to form special
purpose finance vehicles to issue securitization bonds to recover the deferred
costs, with interest. CIPS, CILCO and IP each have less than one million
retail customers. This approach has the effect of spreading over the life of
the
bonds, a period of up to 10 years, the significant initial electric rate
increase for residential customers that would otherwise be necessary to pay
the
power supply costs on a current basis. This legislation was not adopted during
the spring session.
Summary
We
are
unable to predict the results of the court appeals of the January 2006 ICC
order
approving CIPS’, CILCO’s and IP’s power procurement auction and the related
tariffs, nor can we predict the actions the Illinois General Assembly and
governor may take which may impact electric rates or the power procurement
process for CIPS, CILCO and IP after the expiration of the current Illinois
electric rate freeze on January 1, 2007, and power supply contracts on December
31, 2006. Any decision or action that impairs the ability of CIPS, CILCO and
IP
to fully recover purchased power or distribution costs from their electric
customers in a timely manner would result in material adverse consequences
to
Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a
significant drop in credit ratings to deep junk status, a loss of access to
the
capital markets, higher borrowing costs, higher power supply costs, an inability
to make timely energy infrastructure investments, significant risk of disruption
in electric and gas service, significant job losses, and financial insolvency.
In addition, Ameren, CILCORP and IP could be required to record a one-time
charge for goodwill impairment related to goodwill that was recorded when Ameren
acquired these companies. As of September 30, 2006, Ameren, CILCORP and IP
had
$976 million, $575 million and $326 million, respectively, of goodwill recorded
on their balance sheets. Furthermore, if the Ameren Illinois utilities are
unable to recover their costs from customers, the utilities could be required
to
cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation”, which allows CIPS, CILCO and IP to defer certain costs pursuant to
actions of rate regulators. This
would result in the elimination of all regulatory assets recorded by CIPS,
CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary
charge on their statements of income that could be material. As of September
30,
2006, CIPS, CILCORP, CILCO and IP had $35 million, $12 million, $12 million
and
$197 million, respectively, recorded as regulatory assets on their balance
sheets.
Ameren,
CIPS, CILCORP, CILCO and IP continue to explore a number of legal and regulatory
actions, strategies and alternatives to address these Illinois electric issues.
CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to
protect their financial interests, including seeking the protection of the
bankruptcy courts. There can be no assurance that Ameren, CIPS, CILCORP, CILCO
and IP will prevail over the stated opposition by certain Illinois legislators,
the Illinois attorney general, the Illinois governor, and other stakeholders,
or
that the legal and regulatory actions, strategies and alternatives that Ameren,
CIPS, CILCORP, CILCO and IP are considering will be successful.
Federal
Hydroelectric
License Renewal
In
May
2005, UE, the U.S. Department of the Interior and various state agencies reached
a settlement agreement that is expected to lead to FERC’s relicensing of UE’s
Osage hydroelectric plant for another 40 years. The settlement must be approved
by FERC. Approval and relicensure are expected by the end of 2006. The current
FERC license expired on February 28, 2006. Operations are permitted to continue
under the expired license until the license renewal is approved.
Joint
Dispatch Agreement
See
Note
7 - Related Party Transactions for a description of the JDA among UE, CIPS
and
Genco.
January
2006 JDA Amendment
As
a
result of the February 2005 MoPSC order approving the transfer of UE’s Illinois
service territory to CIPS that was completed on May 2, 2005, the provision
in
the JDA that determines the allocation between UE and Genco of margins from
short-term sales of excess generation to third parties had to be modified.
Specifically, the MoPSC order required an amendment so that margins on
third-party short-term power sales of excess generation would be allocated
between UE and Genco based on generation output, not on load requirements,
as
the agreement had provided. In March 2006, FERC approved the amendment filed
by
UE, CIPS and Genco, effective January 10, 2006. This change in the allocation
methodology resulted in a $3 million and $17 million transfer of electric
margins from Genco to UE during the three months and nine months ended September
30, 2006, respectively.
Termination
of JDA
On
July
7, 2006, UE, CIPS and Genco mutually consented to waive a one-year termination
notice requirement of the JDA and agreed to terminate it on December 31, 2006.
This action with respect to the JDA was accepted by the FERC in September
2006.
36
The
benefits of the JDA to UE and Genco have changed recently due to the emergence
of transparent wholesale markets, the dispatching of generation being conducted
by MISO, and changes to the Illinois regulatory framework, among other things.
As a result, UE believes the benefit it will receive from retaining the power
it
was transferring under the JDA to Genco at incremental cost will exceed the
benefit it would have received from being able to call upon Genco's generation
under the JDA at incremental cost. Since UE was prepared to immediately provide
Genco with one-year notice of termination in June 2006, Genco believes the
potential benefit it could receive from being able to call upon UE's generation
through June 2007 is outweighed by, among other things, the negative
consequences associated with the continued existence of the JDA past December
31, 2006. In particular, Genco believes that the JDA is no longer necessary
or
effective in dispatching Genco's generation jointly with that of UE due to
changes in the marketplace for the sale of electricity, including the MISO
Day
Two Energy Market, and the centralized dispatching of generation by MISO.
Additionally, the JDA is based on a combined control area for the UE and CIPS
transmission facilities located in Missouri and Illinois,
respectively. This combined control area creates operational inefficiencies
for Genco to effectively participate through Marketing Company in the Illinois
power procurement auction to supply power beginning January 1, 2007. In
conjunction with terminating the JDA, Ameren's transmission-owning entities
intend to restructure their control areas so as to have one control area in
Missouri for UE's transmission facilities and one in Illinois for the
transmission facilities of CIPS, CILCO and IP.
As
a
result of the termination of the JDA on December 31, 2006, UE and Genco will
no
longer have the obligation to provide power to each other. In 2005, Genco
received from UE under the JDA net transfers of 8.7 million megawatthours of
power at an average price of $18 per megawatthour and generated 14.2 million
megawatthours of power from its plants at an average cost of approximately
$18
per megawatthour. This power, along with 2.0 million megawatthours purchased
from EEI, was used in 2005 to supply CIPS' load and other wholesale and retail
customers at an average selling price of $35 per megawatthour. In 2005, Genco
also sold 3.3 million net megawatthours of power in the interchange market
at an
average price of $47 per megawatthour. Upon termination of the JDA, Genco will
no longer receive the margins on sales that were supplied with power from UE.
Ameren's
and UE’s earnings will be affected by the termination of the JDA when UE's rates
are adjusted by the MoPSC. As discussed under Missouri Electric in this Note,
UE
filed a request in July 2006 with the MoPSC to increase its electric rates
by
$361 million. UE's requested increase is net of the decrease in its revenue
requirement resulting from increased margins expected to result from the
termination of the JDA.
The
ultimate impact of the termination of the JDA and the MoPSC’s treatment of the
effects of such termination in UE’s current rate case proceeding on the Ameren
Companies’ results of operations, financial position, or liquidity cannot be
predicted at this time.
Leveraged
Leases
Ameren
owns interests in certain assets that were acquired through the acquisition
of
CILCORP and financed as leveraged leases. By an order dated April 15, 2004,
issued pursuant to PUHCA 1935, the SEC determined that certain nonutility
interests and investments of CILCORP and its subsidiaries, including investments
in several leveraged leases, are not retainable by Ameren. The April 2004 SEC
order required that Ameren cause its subsidiaries to sell or otherwise dispose
of the nonretainable interests. The nonretainable interests primarily consist
of
lease interests in commercial real estate properties and equipment. The SEC
approved the divestiture transaction structure proposed by Ameren in December
2005.
Ameren,
CILCORP and CILCO recognized net after-tax losses of $4 million, $4 million
and
$6 million, respectively, from the sale of two leveraged leases in the second
quarter of 2006.
Ameren
and several of its registrant and nonregistrant subsidiaries are pursuing the
sale of their interests in four remaining leveraged lease assets.
NOTE
3 - CREDIT FACILITIES AND LIQUIDITY
The
liquidity needs of the Ameren Companies are typically supported through the
use
of available cash, commercial paper issuances and drawings under committed
bank
credit facilities. The following table summarizes the short-term borrowing
activity and relevant interest rates as of September 30, 2006, and December
31,
2005, respectively:
Ameren
|
UE
|
|||||
September
30, 2006:
|
||||||
Average
daily borrowings outstanding during 2006
|
$
|
276
|
$
|
246
|
||
Weighted-average
interest rate during 2006
|
5.06
|
%
|
5.05
|
%
|
||
Peak
short-term borrowings during 2006
|
$
|
602
|
$
|
470
|
||
Peak
interest rate during 2006
|
5.55
|
%
|
5.55
|
%
|
37
Ameren
|
UE
|
|||||
December
31, 2005:
|
||||||
Average
daily borrowings outstanding during 2005
|
$
|
162
|
$
|
135
|
||
Weighted-average
interest rate during 2005
|
3.02
|
%
|
2.87
|
%
|
||
Peak
short-term borrowings during 2005
|
$
|
578
|
$
|
424
|
||
Peak
interest rate during 2005
|
4.71
|
%
|
4.52
|
%
|
At
September 30, 2006, Ameren and certain of its subsidiaries had $1.65 billion
of
committed credit facilities, consisting of two facilities as described below,
each maturing in July 2010, in the amounts of $1.15 billion and $500 million.
Ameren
could directly borrow under the $1.15 billion facility up to the entire amount
of the facility; UE could directly borrow under this facility up to $500 million
on a 364-day basis; Genco could directly borrow under this facility up to $150
million on a 364-day basis; and until July 13, 2006, CIPS, CILCO and IP could
also each directly borrow under this facility up to $150 million, on a 364-day
basis. On July 14, 2006, the $1.15 billion credit facility was amended. The
amended facility will terminate on July 14, 2010, with respect to Ameren. UE
and
Genco will continue to have the option to seek an annual renewal on a 364-day
basis after their current termination dates. Effective July 13, 2006, the
termination date for UE and Genco was extended to July 12, 2007. CIPS, CILCO
and
IP no longer had borrowing authority under this facility effective July 13,
2006, but remained parties to the agreement until September 8, 2006 as discussed
in the Indebtedness Provisions and Other Covenants section below. Under the
amended facility, Ameren will continue to have $1.15 billion of borrowing
availability. UE and Genco will continue to have $500 million and $150 million,
respectively, of borrowing availability.
Under
the
amended $1.15 billion credit facility, the principal amount of each revolving
loan will be due and payable no later than the final maturity of the facility
in
the case of Ameren and the last day of the then applicable 364-day
period in the case of UE and Genco. The principal amount of each loan will
be
due and payable at the end of the interest period applicable to it, which shall
not be later than the final maturity date of the facility. Swingline loans
will
be made on same-day notice and will mature five business days after they are
made.
Ameren,
UE and Genco will use the proceeds of any borrowings under the amended facility
for general corporate purposes, including for working capital, commercial paper
liquidity support and to fund loans under the Ameren money pool arrangements.
See Exhibit 10.1 to the Current Report on Form 8-K, dated July 18, 2006, for
a
copy of the amended facility.
On
July
14, 2006, CIPS, CILCORP, CILCO, IP and AERG entered into a new $500 million
multiyear, senior secured credit facility. Borrowing authority under this
facility was effective immediately for AERG and CILCORP and effective September
8, 2006, for CIPS, CILCO and IP upon the receipt of regulatory approvals and
the
issuance by CIPS, CILCO and IP of mortgage bonds as security as described below.
Once CIPS, CILCO and IP were authorized to borrow under this new facility,
they
were removed as parties to the $1.15 billion credit facility.
The
obligations of each borrower under the new $500 million facility are several
and
not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren.
The maximum amount available to each borrower, including for issuance of letters
of credit on its behalf, is limited as follows: CIPS - $135 million, CILCORP
-
$50 million, CILCO - $150 million,
IP
- $150
million and AERG - $200 million. In September 2006, AERG drew a $40 million
Eurodollar loan under this credit facility at an interest rate of 6.7%. The
borrowing companies will use the proceeds of any borrowings for working capital
and other general corporate purposes; however, a portion of the borrowings
by
AERG may be limited to financing or refinancing the development, management
and
operation of any of its projects or assets. The new facility will terminate
on
January 14, 2010.
The
obligations of CIPS, CILCO and IP under the new facility are secured by the
issuance on September 8, 2006, of mortgage bonds by each such utility under
its
respective mortgage indenture in the amounts of $135 million, $150 million
and
$150 million, respectively. The obligations of CILCORP under the facility are
secured by a pledge of the common stock of CILCO. The obligations of AERG are
secured by a mortgage and security interest in its E.D. Edwards and Duck Creek
power plants and related licenses, permits and similar rights. See Exhibit
10.2
to the Current Report on Form 8-K, dated July 18, 2006, for a copy of the new
facility.
As
a
condition to the amendment of the $1.15 billion credit facility and the closing
of the new $500 million credit facility, effective July 14, 2006, Ameren
terminated its $350 million credit facility. Ameren was the only borrower under
this agreement, and there was no early termination penalty.
The
$1.15
billion credit facility, and the $350 million credit facility prior to its
termination, were used to support our commercial paper programs that include
all
outstanding external short-term debt of Ameren and UE as of September 30, 2006,
and December 31, 2005. The $1.15 billion amended facility will continue to
support Ameren’s and UE’s commercial paper programs. Access to
38
the
$1.15
billion credit facility and the $500 million credit facility for the Ameren
Companies are subject to reduction as they are used by affiliates.
In
April
2006, EEI’s $20 million bank credit facility expired and was not
renewed.
Money
Pools
Ameren
has money pool agreements with and among its subsidiaries to coordinate and
provide for certain short-term cash and working capital requirements. Separate
money pools are maintained for utility and non-state-regulated entities.
Through
the utility money pool, the pool participants may access the committed credit
facilities. CIPS, CILCO and IP borrow from each other through the utility money
pool agreement subject to applicable regulatory short-term borrowing
authorizations. While UE and Ameren Services are parties to the utility money
pool agreement, they are not currently borrowing or lending under the agreement.
Ameren Services administers the utility money pool and tracks internal and
external funds separately. Ameren and AERG may participate in the utility money
pool only as lenders. The availability of funds is effectively determined by
funding requirement limits established by regulatory authorizations. The average
interest rate for borrowing under the utility money pool for the three months
and nine months ended September 30, 2006, was 5.4% and 5.0%, respectively (2005
- 3.5% and 3.0%, respectively).
Non-state-regulated
Ameren subsidiaries, including Genco and AERG, have the ability, subject to
Ameren authorization, to access funding from Ameren’s $1.15 billion credit
facility through a non-state-regulated subsidiary money pool agreement subject
to applicable regulatory short-term borrowing authorizations. The
average interest rate for borrowing under the non-state-regulated subsidiary
money pool for the three months and nine months ended September 30, 2006, was
4.8% and 4.6%, respectively (2005 - 4.1% and 5.9%, respectively).
The
total
amount available to the money pool participants at any time is reduced by the
amount of borrowings by their affiliates under existing agreements and is
increased to the extent that other pool participants advance surplus funds
to
the money pool.
See
Note
7 - Related Party Transactions for the amount of interest income and expense
from the money pool arrangements recorded by the Ameren Companies for the three
months and nine months ended September 30, 2006 and 2005.
Indebtedness
Provisions and Other Covenants
The
bank
credit facilities described above contain provisions which, among other things,
place restrictions on the ability to incur liens, sell assets, and merge with
other entities. As discussed above, the $1.15 billion credit facility was
amended effective July 14, 2006. The provisions in the amended facility are
similar to those in the prior facility, including the covenant that limits
total
indebtedness of Ameren, UE and Genco to 65% of total capitalization pursuant
to
a calculation defined in the facility. Exceeding these debt levels would result
in a default under the credit arrangements.
The
amended $1.15 billion credit facility also contains default provisions similar
to those in the prior facility, including cross defaults, with respect to a
borrower under the facility, that can result from the occurrence of an event
of
default under any other facility covering indebtedness of that borrower or
certain of its subsidiaries in excess of $50 million in the aggregate. The
obligations of Ameren, UE and Genco under the amended facility remain several
and not joint, and except under limited circumstances, the obligations of UE
and
Genco are not guaranteed by Ameren or any other subsidiary. With the termination
of CIPS, CILCO and IP as parties to this agreement on September 8, 2006, they
are no longer considered subsidiaries for purposes of the cross-default
provisions nor are CILCORP or AERG.
Under
the
amended $1.15 billion credit facility, restrictions apply limiting investments
in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries
by Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP,
AERG
and their subsidiaries are excluded for purposes of determining compliance
with
the 65% total consolidated indebtedness to total consolidated capitalization
financial covenant that remains in the amended facility.
The
new
$500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG,
discussed above, limits the indebtedness of each borrower to 65% of consolidated
total capitalization pursuant to a calculation set forth in the facility. Events
of default under this facility apply separately to each borrower (and, except
in
the case of CILCORP, their subsidiaries), and an event of default under this
facility does not constitute an event of default under the amended $1.15 billion
credit facility and vice versa. In addition, if CIPS’, CILCO’s or IP’s senior
secured long-term debt securities or first mortgage bonds, or CILCORP’s senior
unsecured long-term debt securities, have received a below investment-grade
credit rating by either Moody’s or S&P, then such borrower will be limited
to capital stock dividend payments of $10 million per year each, while such
below investment-grade credit rating is in effect. On July 26, 2006, Moody’s
downgraded CILCORP’s senior unsecured long-term debt credit rating to below
investment-grade causing it to be subject to this
39
dividend
payment limitation. A similar restriction
applies to AERG if its debt-to-operating cash flow ratio, as set forth in the
facility, is below a specified ratio. As of September 30, 2006, AERG failed
to
meet the debt-to-operating cash flow ratio test in the facility and, therefore,
is currently limited in its ability to pay dividends. CIPS, CILCO and IP are
not
currently limited in their dividend payments by this provision of the $500
million credit facility.
This
new
facility also limits the amount of other secured indebtedness issuable by
each
borrower as follows: for CIPS, CILCO and IP, other secured debt is limited
to
that permitted under their respective mortgage indentures. For CILCORP, other
secured debt is limited to $550 million secured by the pledge of CILCO stock,
and for AERG, other secured debt is limited to $200 million secured on an
equal
basis with its obligations under the new facility. The new facility provides
that
CIPS, CILCO and IP will agree to reserve future bonding capacity under their
respective mortgage indentures (that is, agree to forego the issuance of
additional mortgage bonds otherwise permitted under the terms of each mortgage
indenture) in the following amounts: CIPS, prior to December 31, 2007 - $50
million, on and after December 31, 2007, but prior to December 31, 2008 -
$100
million, on and after December 31, 2008 - $150 million; CILCO - $25 million;
and
IP - $100 million. In addition, the new credit facility prohibits CILCO from
issuing any preferred stock if after giving effect to such issuance the
aggregate liquidation value of all CILCO preferred stock issued after July
14,
2006, would exceed $50 million.
As
of
September 30, 2006, the ratio of total indebtedness to total capitalization,
calculated in accordance with the provisions of the $1.15 billion credit
facility for Ameren, UE and Genco was 50%, 47% and 51%, respectively. The ratio
for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the
provisions of the $500 million credit facility, were 47%, 55%, 37%, 44% and
25%,
respectively.
None
of
Ameren’s credit facilities or financing arrangements contain credit rating
triggers that would cause an event of default or acceleration of repayment
of
outstanding balances. At September 30, 2006, the Ameren Companies were in
compliance with their credit facility provisions and covenants.
NOTE
4 - LONG-TERM
DEBT AND EQUITY FINANCINGS
Ameren
Under
DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under
our 401(k) plans, pursuant to effective SEC Form S-8 registration statements,
Ameren issued a total of 0.4 million new shares of common stock valued at $21
million and 1.5 million new shares valued at $78 million in the three months
and
nine months ended September 30, 2006, respectively.
UE
UE’s
debt
increased $240 million in the first quarter of 2006 as a result of the capital
lease assigned to it in connection with the acquisition from affiliates of
NRG
Energy, Inc. of a 640-megawatt CT facility located in Audrain County, Missouri.
No capital was raised as a result of UE’s assumption of the lease
obligations.
CIPS
In
June
2006, CIPS issued and sold, pursuant to an effective SEC Form S-3 registration
statement, $61 million of 6.70% senior secured notes due June 15, 2036, with
interest payable semi-annually on June 15 and December 15 of each year,
beginning in December 2006. These notes are secured by first mortgage bonds,
which are subject to fallaway provisions, as defined in the related financing
agreements. CIPS received net proceeds of $60 million, which were used, among
other funds, to repay in full CIPS’ intercompany note payable to
UE.
Also
in
June 2006, $20 million of CIPS’ 7.05% first mortgage bonds matured and were
retired.
See
Note
3 - Credit Facilities and Liquidity regarding first mortgage bonds issued by
CIPS in September 2006 as security for its obligations under the $500 million
credit facility.
CILCORP
In
March
2006, CILCORP repurchased $2 million in principal amount of its 9.375% senior
bonds due 2029, and in April 2006, CILCORP repurchased an additional $7 million
in principal amount of these bonds.
In
conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was
recorded at fair value. Amortization related to these fair value adjustments
was
$1 million (2005 - $2 million) and $4 million (2005 - $6 million) for the three
months and nine months ended September 30, 2006, respectively, and was included
as a reduction to interest expense in the Consolidated Statements of Income
of
Ameren and CILCORP. See Note 3 - Credit Facilities and Liquidity regarding
CILCORP’s pledge of the common stock of CILCO as security for CILCORP’s
obligations under the $500 million credit facility.
CILCO
In
June
2006, CILCO issued and sold, with registration rights in a private placement,
$54 million of 6.20% senior secured notes due June 15, 2016, and $42 million
of
6.70%
40
senior
secured notes due June 15, 2036, both with
interest payable semi-annually on June 15 and December 15 of each year,
beginning in December 2006. These notes are secured by first mortgage bonds,
which are subject to fallaway provisions as defined in the related financing
agreements. CILCO received total net proceeds of $95 million which were used
to
reduce short-term money pool borrowings and, in July 2006, to redeem CILCO’s $20
million 7.73% secured medium-term notes due 2025. CILCO
commenced the offer to exchange registered secured notes for the outstanding
unregistered senior secured notes under the related registration rights
agreement on October 18, 2006. Unless extended, the exchange offer will expire
on November 16, 2006.
In
July
2006, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at
a
redemption price of $100
per
share plus accrued and unpaid dividends. The redemption satisfied CILCO’s
mandatory sinking fund redemption requirement for this series of preferred
stock
for 2006.
See
Note
3 - Credit Facilities and Liquidity regarding first mortgage bonds issued by
CILCO and the mortgage and security interest in its power plants issued by
AERG
in September 2006 as security for their respective obligations under the $500
million credit facility.
IP
In
June
2006, IP issued and sold, with registration rights in a private placement,
$75
million of 6.25% senior secured notes due June 15, 2016, with interest payable
semi-annually on June 15 and December 15 of each year, beginning in December
2006. These notes are secured by mortgage bonds, which are subject to fallaway
provisions as defined in the related financing agreements. IP received net
proceeds of $74 million, which were used to reduce short-term money pool
borrowings. IP commenced the offer to exchange registered secured notes for
the
outstanding unregistered senior secured notes under the related registration
rights agreement on October 18, 2006. Unless extended, the exchange offer will
expire on November 16, 2006.
In
conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at
fair value. Amortization related to these
fair value adjustments was $3 million (2005 - $3 million and $10 million (2005
-
$12 million) for the three months and nine months ended September 30, 2006,
respectively, and was included as a reduction to interest expense in the
Consolidated Statements of Income of Ameren and IP.
See
Note
3 - Credit Facilities and Liquidity regarding mortgage bonds issued by IP in
September 2006 as security for its obligations under the $500 million credit
facility.
Indenture
Provisions and Other Covenants
The
information below presents a summary of the Ameren Companies’ compliance with
indenture provisions and other
covenants. See Note 6 - Long-term Debt and Equity Financings in the Ameren
Companies’ combined Annual Report on Form 10-K for the fiscal year ended
December 31, 2005, for a detailed description of those provisions.
UE’s,
CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation
include covenants and provisions related to the issuances of first mortgage
bonds and preferred stock. The following table includes the required and actual
earnings coverage ratios for interest charges and preferred dividends along
with
bonds and preferred stock issuable based on the 12 months ended September 30,
2006, at an assumed interest and dividend rate of 7%.
Required
Interest Coverage Ratio(a)(b)
|
Actual
Interest
Coverage
Ratio
|
Bonds
Issuable(c)(d)
|
Required
Dividend Coverage Ratio(e)
|
Actual
Dividend
Coverage
Ratio
|
Preferred
Stock
Issuable
|
|||||||||||||
UE
|
2.0
|
4.4
|
2,150
|
2.5
|
41.4
|
1,319
|
||||||||||||
CIPS
|
2.0
|
4.0
|
149
|
1.5
|
2.2
|
210
|
||||||||||||
CILCO
|
2.0(f
|
)
|
9.1
|
200
|
2.5
|
17.4
|
166(g
|
)
|
||||||||||
IP
|
2.0
|
5.7
|
620
|
1.5
|
2.5
|
420
|
(a)
Coverage
required on the annual interest charges on first mortgage bonds outstanding
and
to be issued.
(b)
Coverage
is not required in certain cases when additional mortgage bonds are issued
on
the basis of retired bonds.
(c) |
Amount
of bonds issuable based on either meeting required coverage ratios
or
unfunded property additions and retired bonds, whichever is more
restrictive.
|
(d) |
Amounts
are net of future bonding capacity restrictions agreed to by CIPS,
CILCO
and IP under the $500 million credit facility entered into by these
companies. See Note 3 - Credit Facilities and Liquidity for further
discussion.
|
(e) |
Coverage
required on the annual interest charges on all long-term debt (CIPS-only)
and the annual dividend on preferred stock outstanding and to be
issued,
as required in the respective company’s articles of incorporation. For
CILCO, this ratio must be met for a period of 12 consecutive calendar
months within the 15 months immediately preceding the
issuance.
|
(f) |
In
lieu of meeting the interest coverage ratio requirement, CILCO may
attempt
to meet an earnings requirement of at least 12% of the principal
amount of
all mortgage bonds outstanding and to be issued. For the three months
and
nine months ended September 30, 2006, CILCO had earnings equivalent
to at
least 44% of the principal amount of all mortgage bonds
outstanding.
|
(g) |
See
Note 3 - Credit Facilities and Liquidity for a discussion regarding
a
restriction on the issuance of preferred stock by CILCO under the
$500
million credit facility.
|
41
In
addition, UE’s mortgage indenture contains certain provisions that restrict the
amount of common dividends that can be paid by UE. Under this mortgage
indenture, $31 million of retained earnings was restricted against payment
of
common dividends, except those dividends payable in common stock, which left
$1.8 billion of free and unrestricted retained earnings at September 30,
2006.
The
ICC
order approving Ameren’s acquisition of IP contains a provision that gives IP
the ability to declare and pay $80
million of dividends on its common stock in 2005 and
$160
million of dividends on its common stock cumulatively through 2006, provided
IP
has achieved an investment-grade credit rating from S&P or Moody’s. On
October 5, 2006, S&P downgraded IP’s credit ratings to the lowest
investment-grade
rating
and placed them on credit watch with negative implications. On October 10,
2006,
Moody’s placed IP’s long-term credit ratings under review for possible
downgrade. If IP’s $550 million principal amount of 11.50% Series mortgage bonds
due 2010 are not eliminated by December 31, 2006, IP may not thereafter declare
or pay common dividends without seeking authority from the ICC. As of September
30, 2006, $33,000
of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds become
callable in December 2006.
Genco’s
and CILCORP’s indentures include provisions that require the companies to
maintain certain debt service coverage and debt-to-capital ratios in order
for
the companies to pay dividends, make certain principal or interest payments,
make certain loans to affiliates, or incur additional indebtedness. The
following table summarizes these ratios for the 12 months ended September 30,
2006:
Required
Interest
Coverage
Ratio
|
Actual
Interest
Coverage
Ratio
|
Required
Debt-to-
Capital
Ratio
|
Actual
Debt-to-
Capital
Ratio
|
|
Genco
(a)
|
≥1.75(b)
|
3.9
|
≤60%
|
50%
|
CILCORP(c)
|
≥2.2
|
2.6
|
≤67%
|
40%
|
(a) |
Interest
coverage ratio relates to covenants regarding certain dividend, principal
and interest payments on certain subordinated intercompany borrowings.
The
debt-to-capital ratio relates to a debt incurrence covenant, which
also
requires an interest coverage ratio of 2.5 for the most recently
ended
four fiscal quarters.
|
(b) |
Ratio
excludes amounts payable under Genco’s intercompany note to CIPS and must
be met for both the prior four fiscal quarters and for the four succeeding
six-month periods.
|
(c) |
CILCORP
must maintain the required interest coverage ratio and debt-to-capital
ratio in order to make any payment of dividends or intercompany loans
to
affiliates other than to its direct or indirect
subsidiaries.
|
In
order
for the Ameren Companies to issue securities in the future, they will have
to
comply with any applicable tests in effect at the time of any such
issuances.
Off-Balance-Sheet
Arrangements
At
September 30, 2006, none of the Ameren Companies had any off-balance-sheet
financing arrangements, other than operating leases entered into in the ordinary
course of business. None of the Ameren Companies expect to engage in any
significant off-balance-sheet financing arrangements in the near
future.
NOTE
5 -
OTHER INCOME AND EXPENSES
The
following table presents Other Income and Expenses for each of the Ameren
Companies for the three months and nine months ended September 30, 2006 and
2005:
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren:(a)
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
2
|
$
|
3
|
$
|
5
|
$
|
5
|
||||
Allowance
for equity funds used during construction
|
1
|
3
|
2
|
10
|
||||||||
Other
|
2
|
-
|
6
|
4
|
||||||||
Total
miscellaneous income
|
$
|
5
|
$
|
6
|
$
|
13
|
$
|
19
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(3
|
)
|
$
|
(1
|
)
|
$
|
(4
|
)
|
$
|
(7
|
)
|
Total
miscellaneous expense
|
$
|
(3
|
)
|
$
|
(1
|
)
|
$
|
(4
|
)
|
$
|
(7
|
)
|
UE:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
-
|
$
|
-
|
$
|
2
|
$
|
-
|
||||
Allowance
for equity funds used during construction
|
1
|
3
|
1
|
9
|
||||||||
Other
|
1
|
-
|
3
|
3
|
||||||||
Total
miscellaneous income
|
$
|
2
|
$
|
3
|
$
|
6
|
$
|
12
|
42
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
(7
|
)
|
$
|
(6
|
)
|
Total
miscellaneous expense
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
(7
|
)
|
$
|
(6
|
)
|
CIPS:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
4
|
$
|
4
|
$
|
12
|
$
|
13
|
||||
Other
|
-
|
-
|
1
|
-
|
||||||||
Total
miscellaneous income
|
$
|
4
|
$
|
4
|
$
|
13
|
$
|
13
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
-
|
$
|
(1
|
)
|
$
|
(1
|
)
|
$
|
(5
|
)
|
|
Total
miscellaneous expense
|
$
|
-
|
$
|
(1
|
)
|
$
|
(1
|
)
|
$
|
(5
|
)
|
|
Genco:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Other
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
1
|
||||
Total
miscellaneous income
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
1
|
||||
CILCORP:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
-
|
$
|
-
|
$
|
1
|
$
|
-
|
||||
Total
miscellaneous income
|
$
|
-
|
$
|
-
|
$
|
1
|
$
|
-
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(7
|
)
|
Total
miscellaneous expense
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(7
|
)
|
CILCO:
|
||||||||||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(5
|
)
|
Total
miscellaneous expense
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(5
|
)
|
IP:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
1
|
$
|
1
|
$
|
2
|
$
|
3
|
||||
Allowance
for equity funds used during construction
|
-
|
-
|
-
|
1
|
||||||||
Other
|
1
|
1
|
2
|
2
|
||||||||
Total
miscellaneous income
|
$
|
2
|
$
|
2
|
$
|
4
|
$
|
6
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(1
|
)
|
$
|
-
|
$
|
(3
|
)
|
$
|
(1
|
)
|
|
Total
miscellaneous expense
|
$
|
(1
|
)
|
$
|
-
|
$
|
(3
|
)
|
$
|
(1
|
)
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
NOTE
6 - DERIVATIVE FINANCIAL INSTRUMENTS
The
pretax net gain or loss on power forward hedges is included in Operating
Revenues - Electric, and the pretax net gain or loss on hedges related to
SO2
emission allowances,
fuel or power supply, and natural gas are included in Operating Expenses -
Fuel
and Purchased Power. This pretax net gain or loss represents the impact of
discontinued cash flow hedges, the ineffective portion of cash flow hedges,
and
the
reversal of amounts previously recorded in OCI due to transactions being
delivered or settled, resulting in a $3
million gain for Ameren, a $2 million gain for UE, and a $1 million gain for
Genco for the three months ended September 30, 2006 (2005 - $1 million loss
for
Ameren, $1 million loss for UE, $1 million loss for Genco), and a $2 million
gain for Ameren, a $2 million gain for UE, and a $2 million loss for IP for
the
nine months ended September 30, 2006 (2005 - $2 million gain for Ameren, $1
million loss for UE).
43
The
following table presents the carrying value of all derivative instruments and
the amount of pretax net gains (losses) on derivative instruments in Accumulated
OCI for cash flow hedges as of September 30, 2006:
Ameren(a)
|
UE
|
CIPS
|
Genco
|
CILCORP/
CILCO
|
IP
|
|||||||||||||
Derivative
instruments carrying value:
|
||||||||||||||||||
Total
assets
|
$
|
79
|
$
|
11
|
$
|
2
|
$
|
3
|
$
|
9
|
$
|
5
|
||||||
Total
deferred credits and liabilities
|
16
|
6
|
-
|
1
|
-
|
1
|
||||||||||||
Gains
(losses) deferred in Accumulated OCI:
|
||||||||||||||||||
Power
forwards and swaps(b)
|
54
|
7
|
-
|
3
|
-
|
(1
|
)
|
|||||||||||
Interest
rate swaps(c)
|
3
|
-
|
-
|
3
|
-
|
-
|
||||||||||||
Gas
swaps and futures contracts(d)
|
9
|
1
|
2
|
-
|
9
|
-
|
||||||||||||
SO2
futures contracts
|
(1
|
)
|
-
|
-
|
(1
|
)
|
-
|
-
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
(b) |
Represents
the mark-to-market value for the hedged portion of electricity price
exposure for periods of up to four years, including $30 million over
the
next year.
|
(c) |
Represents
a gain associated with interest rate swaps at Genco that were a partial
hedge of the interest rate on debt issued in June 2002. The swaps
cover
the first 10 years of debt that has a 30-year maturity and the gain
in OCI
is amortized over a 10-year period that began in June
2002.
|
(d) |
Represents
gains associated with natural gas swaps and futures contracts. The
swaps
are a partial hedge of our natural gas requirements through March
2011.
|
Other
Derivatives
The
following table presents the net change in market value for the three months
and
nine months ended September 30, 2006 and 2005, of option and swap transactions
used to manage our positions in SO2
allowances. Certain of these transactions are treated as nonhedge transactions
under SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities.” The net change in the market value of power options is recorded in
Operating Revenues - Electric, while the net change in the market value of
coal,
heating oil and SO2
options
and swaps is recorded as Operating Expenses - Fuel and Purchased
Power.
Three
Months
|
Nine
Months
|
|||||||||||
Gains
(Losses)
|
2006
|
2005
|
2006
|
2005
|
||||||||
SO2
options and swaps:
|
||||||||||||
Ameren
|
$
|
1
|
$
|
(4
|
)
|
$
|
(2
|
)
|
$
|
(10
|
)
|
|
UE
|
1
|
(4
|
)
|
3
|
(5
|
)
|
||||||
Genco
|
-
|
-
|
(4
|
)
|
(5
|
)
|
||||||
CILCORP/CILCO
|
-
|
-
|
(1
|
)
|
-
|
|||||||
Coal
Options:
|
||||||||||||
Ameren
|
(1
|
)
|
-
|
(2
|
)
|
1
|
||||||
UE
|
(1
|
)
|
1
|
(2
|
)
|
1
|
NOTE
7 - RELATED
PARTY TRANSACTIONS
The
Ameren Companies have engaged in, and may in the future engage in, affiliate
transactions in the normal course of business. These transactions primarily
consist of gas and power purchases and sales, services received or rendered,
and
borrowings and lendings. Transactions between affiliates are reported as
intercompany transactions on their financial statements, but are eliminated
in
consolidation for Ameren’s
financial statements. For a discussion of our material related party
agreements, see Note 14 - Related Party Transactions under Part II, Item 8
of
the Ameren Companies’ combined Annual
Report on Form 10-K for the fiscal year ended December 31, 2005. Below are
updates to several of these related party agreements.
Electric
Power Supply Agreements
The
following table presents the amount of gigawatthour sales under related party
electric power supply agreements for the three months and nine months ended
September 30, 2006 and 2005:
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Genco
sales to Marketing
Company
|
5,820
|
6,788
|
16,707
|
16,884
|
||||||||
Marketing
Company sales
to CIPS
|
3,424
|
3,565
|
9,500
|
8,118
|
||||||||
EEI
sales to UE
|
-
|
789
|
-
|
2,230
|
||||||||
EEI
sales to CIPS
|
-
|
394
|
-
|
1,337
|
||||||||
EEI
sales to IP
|
-
|
433
|
-
|
1,227
|
The
agreement under which EEI supplied power to UE, CIPS (which resold its
entitlement to Marketing Company) and IP expired on December 31, 2005. EEI
billed residual amounts under this contract in the first quarter of 2006 of
$3
million, $2 million and $1 million to UE, CIPS and IP, respectively. CIPS’
obligation to pay the residual amount of $2 million was transferred to Marketing
Company, to which CIPS had sold power supplied by EEI under the agreement.
Beginning January 1, 2006, EEI entered into a new agreement to sell 100% of
its
capacity and energy to Marketing Company at market prices through December
31,
2015.
In
accordance with the January 2006 ICC order discussed in Note 2 - Rate and
Regulatory Matters, a power procurement auction was held at the beginning of
September 2006 to procure power for CIPS, CILCO and IP after current power
supply contracts expire on December 31, 2006. On September 15, 2006, the
independent auction manager (NERA Economic Consulting) declared a successful
result in the auction for fixed-price customers. In conjunction with the
auction, there is a limitation of 35% on the amount of power any single supplier
can provide of the Ameren Illinois utilities’ expected annual load.
Ameren-affiliated companies are
44
considered
one supplier for the purposes of this limitation. Marketing Company was awarded
contracts in the auction.
Joint
Dispatch Agreement
UE
and
Genco jointly dispatch electric generation under the JDA among UE, CIPS and
Genco. UE and Genco have the option to serve their load requirements from their
own generation first, and then each may give its affiliates access to any
available generation at incremental cost. Any excess generation not used by
UE
or Genco to serve load requirements is sold to third parties on a short-term
basis through Ameren Energy, which serves as each affiliate’s agent. To allocate
power costs between UE and Genco, an intercompany sale is recorded by the
company sourcing the power to the other company. Ameren Energy also acts as
an
agent on behalf of UE and Genco to purchase power when they require it. As
further discussed in Note 2 - Rate and Regulatory Matters, in January 2006,
the
allocation methodology in the JDA for margins on short-term sales of excess
generation to third parties between UE and Genco was modified, and on July
7,
2006, UE, CIPS and Genco mutually consented to waive the one-year termination
notice requirement of the JDA and agreed to terminate it on December 31, 2006.
This action with respect to the JDA was accepted by the FERC in September
2006.
The
following table presents the amount of gigawatthour sales under the JDA for
the
three months and nine months ended September 30, 2006 and 2005:
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
UE
sales to Genco
|
2,073
|
2,361
|
7,507
|
8,807
|
||||||||
Genco
sales to UE
|
898
|
636
|
2,615
|
2,365
|
The
following table presents the short-term power sales margins under the JDA for
UE
and Genco for the three months and nine months ended September 30, 2006 and
2005:
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
UE
|
$
|
15
|
$
|
18
|
$
|
73
|
$
|
97
|
||||
Genco
|
5
|
9
|
22
|
56
|
||||||||
Total
|
$
|
20
|
$
|
27
|
$
|
95
|
$
|
153
|
Money
Pools
See
Note
3 - Credit Facilities and Liquidity for discussion of affiliate borrowing
arrangements.
Intercompany
Promissory Notes
Genco’s
subordinated note payable to CIPS associated with the transfer of CIPS’ electric
generating assets and related liabilities to Genco matures on May 1, 2010.
Interest income and expense for this note recorded by CIPS and Genco,
respectively, was $3 million (2005 - $4 million) and $10 million (2005 - $12
million) for the three months and nine months ended September 30, 2006 and
2005.
In
June
2006, CIPS repaid in full the remaining balance under its May 2005, $67 million
subordinated promissory note to UE.
The
average interest rate on CILCORP’s note payable to Ameren was 4.8% and 4.5% for
the three months and nine months ended September 30, 2006, respectively (2005
-
4.1% and 6.7%, respectively). CILCORP recorded interest expense of $2 million
(2005 - $1 million) and $6 million (2005 - $4 million) for the three months
and
nine months ended September 30, 2006, respectively.
The
following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and
IP
of related party transactions for the three months and nine months ended
September 30, 2006 and 2005. It is based primarily on the agreements discussed
above and in Note 14 - Related Party Transactions under Part II, Item 8 of
the
Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended
December 31, 2005, and the money pool arrangements discussed above in Note
3 -
Credit Facilities and Liquidity of this report.
Three
Months
|
Nine
Months
|
|||||||||||||||||||||||||||||||||
Agreement
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
||||||||||||||||||||||||
Operating
Revenues:
|
||||||||||||||||||||||||||||||||||
Power
supply agreement
|
2006
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
216
|
$
|
(c
|
)
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
605
|
$
|
5
|
$
|
(b
|
)
|
||||||
with
Marketing Company
|
2005
|
(b
|
)
|
8
|
229
|
2
|
(b
|
)
|
(b
|
)
|
25
|
603
|
23
|
(b
|
)
|
|||||||||||||||||||
Power
supply agreement with
EEI
|
2005
|
(c
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
|||||||||||||
UE
and Genco gas
|
2006
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
|||||||||||||
transportation
agreement
|
2005
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
|||||||||||||
JDA
|
2006
|
35
|
(b
|
)
|
23
|
(b
|
)
|
(b
|
)
|
156
|
(b
|
)
|
69
|
(b
|
)
|
(b
|
)
|
|||||||||||||||||
2005
|
50
|
(b
|
)
|
26
|
(b
|
)
|
(b
|
)
|
147
|
(b
|
)
|
57
|
(b
|
)
|
(b
|
)
|
||||||||||||||||||
Total
Operating
|
2006
|
$
|
35
|
$
|
(b
|
)
|
$
|
239
|
$
|
(c
|
)
|
$
|
(b
|
)
|
$
|
156
|
$
|
(b
|
)
|
$
|
674
|
$
|
5
|
$
|
(b
|
)
|
||||||||
Revenues
|
2005
|
50
|
8
|
255
|
2
|
(b
|
)
|
147
|
25
|
660
|
23
|
(b
|
)
|
|||||||||||||||||||||
Fuel
and Purchased Power:
|
||||||||||||||||||||||||||||||||||
JDA
|
2006
|
$
|
23
|
$
|
(b
|
)
|
$
|
35
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
69
|
$
|
(b
|
)
|
$
|
156
|
$
|
(b
|
)
|
$
|
(b
|
)
|
|||||||
2005
|
26
|
(b
|
)
|
50
|
(b
|
)
|
(b
|
)
|
57
|
(b
|
)
|
147
|
(b
|
)
|
(b
|
)
|
45
Three
Months
|
Nine
Months
|
|||||||||||||||||||||||||||||||||
Agreement
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
||||||||||||||||||||||||
Power
supply agreement
|
2006
|
$
|
(b
|
)
|
$
|
118
|
$
|
(b
|
)
|
$
|
1
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
337
|
$
|
(b
|
)
|
$
|
1
|
$
|
(b
|
)
|
|||||||
with
Marketing Company
|
2005
|
(b
|
)
|
121
|
2
|
3
|
(b
|
)
|
4
|
291
|
4
|
10
|
(b
|
)
|
||||||||||||||||||||
Power
supply agreement with
EEI
|
2005
|
16
|
8
|
(b
|
)
|
(b
|
)
|
13
|
46
|
25
|
(b
|
)
|
(b
|
)
|
40
|
|||||||||||||||||||
Executory
tolling agreement
|
2006
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
9
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
29
|
(b
|
)
|
|||||||||||||||
with
Medina Valley
|
2005
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
9
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
27
|
(b
|
)
|
|||||||||||||||
UE
and Genco gas
|
2006
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
|||||||||||||
transportation
agreement
|
2005
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
|||||||||||||
Total
Fuel and
|
2006
|
$
|
23
|
$
|
118
|
$
|
35
|
$
|
10
|
$
|
(b
|
)
|
$
|
69
|
$
|
337
|
$
|
156
|
$
|
30
|
$
|
(b
|
)
|
|||||||||||
Purchased
Power
|
2005
|
42
|
129
|
52
|
12
|
13
|
107
|
316
|
151
|
37
|
40
|
|||||||||||||||||||||||
Other
Operating Expenses:
|
||||||||||||||||||||||||||||||||||
Ameren
Services support
|
2006
|
$
|
34
|
$
|
12
|
$
|
7
|
$
|
12
|
$
|
18
|
$
|
103
|
$
|
36
|
$
|
18
|
$
|
37
|
$
|
54
|
|||||||||||||
services
agreement
|
2005
|
38
|
10
|
5
|
9
|
20
|
119
|
32
|
15
|
30
|
42
|
|||||||||||||||||||||||
Ameren
Energy support
|
2006
|
2
|
(b
|
)
|
1
|
(b
|
)
|
(b
|
)
|
6
|
(b
|
)
|
2
|
(b
|
)
|
(b
|
)
|
|||||||||||||||||
services
agreement
|
2005
|
1
|
(b
|
)
|
1
|
(b
|
)
|
(b
|
)
|
3
|
(b
|
)
|
2
|
(b
|
)
|
(b
|
)
|
|||||||||||||||||
AFS
support services
|
2006
|
1
|
(c
|
)
|
(c
|
)
|
(c
|
)
|
1
|
3
|
1
|
1
|
1
|
2
|
||||||||||||||||||||
agreement
|
2005
|
1
|
(c
|
)
|
1
|
1
|
(c
|
)
|
3
|
1
|
2
|
2
|
1
|
|||||||||||||||||||||
Total
Other
|
2006
|
$
|
37
|
$
|
12
|
$
|
8
|
$
|
12
|
$
|
19
|
$
|
112
|
$
|
37
|
$
|
21
|
$
|
38
|
$
|
56
|
|||||||||||||
Operating
Expenses
|
2005
|
40
|
10
|
7
|
10
|
20
|
125
|
33
|
19
|
32
|
43
|
|||||||||||||||||||||||
Interest
Income (Expense):
|
||||||||||||||||||||||||||||||||||
Money
pool borrowings
|
2006
|
$
|
(c
|
)
|
$
|
(1
|
)
|
$
|
3
|
$
|
1
|
$
|
1
|
$
|
(c
|
)
|
$
|
(2
|
)
|
$
|
8
|
$
|
4
|
$
|
2
|
|||||||||
(advances)
|
2005
|
2
|
(1
|
)
|
(1
|
)
|
1
|
(1
|
)
|
4
|
(1
|
)
|
2
|
3
|
(3
|
)
|
(a) |
Amounts
represent CILCORP and CILCO
activity.
|
(b) |
Not
applicable.
|
(c) |
Amount
less than $1 million.
|
NOTE
8 - COMMITMENTS
AND CONTINGENCIES
As
a
result of issues generated in the course of daily business, we are involved
in
legal, tax and regulatory proceedings before various courts, regulatory
commissions, and governmental agencies, some of which involve substantial
amounts of money. We believe that the final disposition of these proceedings,
except as otherwise disclosed in these notes to our financial statements, will
not have an adverse material effect on our results of operations, financial
position, or liquidity.
Reference
is made to Note 1 - Summary of Significant Accounting Policies, Note 3 - Rate
and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 -
Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’
combined Annual Report on Form 10-K for the fiscal year ended December 31,
2005.
Callaway
Nuclear Plant
The
following table presents insurance coverage at UE’s Callaway nuclear plant at
September 30, 2006:
Type
and Source of Coverage
|
Maximum
Coverages
|
Maximum
Assessments for Single Incidents
|
||||
Public
liability:
|
||||||
American
Nuclear Insurers
|
$
|
300
|
$
|
-
|
||
Pool
participation
|
10,461
|
101
|
(a)
|
|||
$ |
10,761
|
(b) |
$
|
101
|
||
Nuclear
worker liability:
|
||||||
American
Nuclear Insurers
|
$
|
300
|
(c)
|
$
|
4
|
|
Property
damage:
|
||||||
Nuclear
Electric Insurance Ltd.
|
$
|
2,750
|
(d)
|
$
|
24
|
|
Replacement
power:
|
||||||
Nuclear
Electric Insurance Ltd.
|
$
|
490
|
(e)
|
$
|
9
|
(a) |
Retrospective
premium under the Price-Anderson liability provisions of the Atomic
Energy
Act of 1954, as amended. This is
subject to retrospective assessment with respect to a covered loss
in
excess of $300 million from an incident at any licensed U.S. commercial
reactor, payable at $15 million per year.
|
(b) |
Limit
of liability for each incident under
Price-Anderson.
|
(c) |
Industry
limit for potential liability from workers claiming exposure to the
hazards of nuclear radiation.
|
(d) |
Includes
premature decommissioning costs.
|
(e) |
Weekly
indemnity of $4.5 million for 52 weeks, which commences after the
first
eight weeks of an outage, plus $3.6 million per week for 71.1 weeks
thereafter.
|
46
Price-Anderson
limits the liability for claims from an incident involving any licensed United
States commercial nuclear power facility. The limit is based on the number
of
licensed reactors and is adjusted at least every five years to reflect changes
in the Consumer
Price Index. Utilities owning a nuclear reactor cover this exposure through
a
combination of private insurance and mandatory participation in a financial
protection pool, as established by Price-Anderson.
If
losses
from a nuclear incident at the Callaway nuclear plant exceed the limits of,
or
are not subject to, insurance, or if coverage is unavailable, UE is at risk
for
any uninsured losses. If a serious nuclear incident occurred, it could have
a
material adverse effect on Ameren and UE’s results of operations, financial
position, or liquidity.
Other
Obligations
To
supply
a portion of the fuel requirements of our generating plants, we have entered
into various long-term commitments for the procurement of coal, natural gas
and
nuclear fuel. In addition, we have entered into various long-term commitments
for the purchase of electricity and natural gas for distribution. For a complete
listing of our obligations and commitments, see Contractual Obligations under
Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II,
Item
8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal
year ended December 31, 2005.
As
of
September 30, 2006, the commitments for the procurement of coal have changed
from amounts previously disclosed as of December 31, 2005. The following table
presents the total estimated coal purchase commitments at September 30, 2006:
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter(a)
|
|||||||||||||
Ameren(b)
|
$
|
116
|
$
|
582
|
$
|
568
|
$
|
432
|
$
|
267
|
$
|
77
|
||||||
UE
|
64
|
311
|
283
|
227
|
174
|
77
|
||||||||||||
Genco
|
22
|
145
|
170
|
143
|
50
|
-
|
||||||||||||
CILCORP/CILCO
|
18
|
49
|
41
|
30
|
21
|
-
|
(a) |
Commitments
for coal are until 2011.
|
(b) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
As
of
September 30, 2006, the commitments for the procurement of natural gas have
changed from amounts previously disclosed as of December 31, 2005. The following
table presents the total estimated natural gas purchase commitments at September
30, 2006:
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter(a)
|
|||||||||||||
Ameren(b)
|
$
|
210
|
$
|
587
|
$
|
427
|
$
|
290
|
$
|
182
|
$
|
248
|
||||||
UE
|
20
|
67
|
57
|
38
|
26
|
75
|
||||||||||||
CIPS
|
30
|
126
|
106
|
71
|
51
|
100
|
||||||||||||
Genco
|
4
|
22
|
19
|
8
|
8
|
10
|
||||||||||||
CILCORP/CILCO
|
86
|
147
|
107
|
60
|
32
|
33
|
||||||||||||
IP
|
61
|
214
|
135
|
111
|
65
|
29
|
(a) |
Commitments
for natural gas are until 2016.
|
(b) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
As
of
September 30, 2006, the long-term commitments for the purchase of electricity
have increased from amounts previously disclosed as of December 31, 2005, as
a
result of power supply contracts obtained by CIPS, CILCO and IP in September
2006 through the operation of the competitive power procurement auction in
Illinois for fixed-price customers, which include the vast majority of electric
customers of these Ameren Illinois utilities. See Note 2 - Rate and Regulatory
Matters for information on the Illinois power procurement auction and related
matters, including pending court appeals that challenge the auction process
and
the recovery by utilities through rates to customers of costs for power supply
resulting from the auction.
CIPS,
CILCO and IP obtained power supply contracts through the September 2006 auction
with terms of 17 months, 29 months and 41 months to serve, commencing
January
1, 2007, the electric load requirements of fixed-price residential and small
commercial customers with less than one megawatt of demand. CIPS, CILCO and
IP
obtained 17-month-term electric power supply contracts to serve the load
requirements of commercial and industrial fixed-price customers with one
megawatt or greater demand commencing January 1, 2007. Under these contracts,
the electric suppliers are responsible for providing to CIPS, CILCO and IP
energy, capacity, certain transmission, volumetric risk management and other
services necessary for the Ameren Illinois utilities to serve the load of
customers at an all inclusive fixed price.
47
Through
the Illinois auction held in September 2006, CIPS, CILCO and IP contracted
for
their anticipated fixed-price loads for residential and small commercial
customers (less than one megawatt of demand) as follows:
Term
Ending
|
|||||||||
May
31, 2008
|
May
31, 2009
|
May
31, 2010
|
|||||||
Term
|
17
Months
|
29
Months
|
41
Months
|
||||||
Load
in megawatts(a)
|
1,822
|
1,874
|
1,874
|
||||||
$
per megawatthour
|
$
|
64.77
|
$
|
64.75
|
$
|
66.05
|
(a) |
Represents
2007 peak forecast load for CIPS, CILCO and IP in the aggregate.
Actual
load could be different due to customers electing not to purchase
power
pursuant to the power procurement auction and receive power from
a
different supplier, and weather, among other things.
|
Through
the Illinois auction held in September 2006, CIPS, CILCO and IP contracted
for
their anticipated fixed-price loads for large commercial and industrial
customers (one megawatt of demand or higher) as follows:
Term
Ending
|
|||
May
31, 2008
|
|||
Term
|
17
Months
|
||
Load
in megawatts(a)
|
1,920
|
||
$
per megawatthour
|
$
|
84.95
|
(a) |
Represents
2007 peak forecast load for CIPS, CILCO and IP in the aggregate.
Actual
load could be different due to customers having 30 to 50 days after
the
date the auction was declared successful (September 15, 2006) to
elect not
to participate and receive power from a different supplier, and weather,
among other things.
|
Environmental
Matters
We
are
subject to various environmental laws and regulations by federal, state and
local authorities. From the beginning phases of siting and development to the
ongoing operation of existing or new electric generating, transmission and
distribution facilities, and natural gas storage plants, our activities involve
compliance with diverse laws and regulations. These laws and regulations address
chemical and waste handling, noise, emissions, and impacts to air, water, and
protected and cultural resources (such as wetlands, endangered species, and
archeological and historical resources). Our activities often require complex
and lengthy processes to obtain regulatory approvals, and permits or licenses
for new, existing or modified facilities. Additionally, the use and handling
of
various chemicals or hazardous materials (including wastes) requires preparation
of release prevention plans and emergency response procedures. As new laws
or
regulations are promulgated, we assess their applicability and implement the
necessary modifications to our facilities or our operations, as required. The
more significant matters are discussed below.
Clean
Air Act
In
May
2005, the EPA issued final regulations with respect to SO2
and
NOx
emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean
Air
Mercury Rule) from coal-fired power plants. The new rules will require
significant reductions in these emissions from UE, Genco, CILCO and EEI power
plants in phases, beginning in 2009. States are required to finalize rules
to
implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule.
While the federal rules mandate a specific emissions cap for SO2,
NOx
and
mercury emissions by state from utility boilers, the states have considerable
flexibility in allocating emission allowances to individual utility boilers.
In
addition, a state may choose to hold back certain emission allowances for growth
or other reasons, and it may implement a more stringent program than the federal
program. Illinois and Missouri are developing proposed rules that will be
subject to public review and comment. We do not expect the state regulations
to
be finalized until the first quarter of 2007. The Illinois EPA-proposed rules
for mercury are significantly stricter than the federal rules. Illinois has
also
proposed Clean Air Interstate Rule program rules for NOx
that are
more stringent than the federal program. The Missouri Department of Natural
Resources is expected to formally propose rules to implement the federal Clean
Air Mercury and Clean Air Interstate Rules in November 2006. The table below
presents preliminary estimated capital costs based on current technology to
comply with both (1) the federal Clean Air Interstate Rule and Clean Air
Mercury Rule
through 2016, and (2) Illinois’ mercury regulations as revised pursuant to an
agreement between Genco, CILCO, EEI, and the Illinois EPA. Under the agreement,
Illinois generators may delay the compliance date for mercury reductions in
exchange for accelerating the installation of NOx
and
SO2
controls. In November 2006, these mercury regulations were approved by the
Illinois Pollution Control Board and are now pending before the Joint Committee
on Administrative Review. The agreement with the Illinois EPA will also restrict
purchasing SO2
and
NOx
emission
allowances to meet specific allowed emission rates set forth in the agreement
and resulted in a $600 million increase in estimated expenditures for the period
of 2006 to 2016. These estimates could change based on new technology,
variations in costs of material or labor, alternative compliance strategies
or
state rulemaking to implement the federal rules, among other reasons. The timing
of estimated capital costs may also be influenced by whether emission credits
are used to comply with the proposed rules, thereby deferring capital
investment.
2006
|
2007
- 2010
|
2011
- 2016
|
Total
|
|||||||||
Ameren
|
$
|
80
|
$
|
1,225
- $1,615
|
$
|
1,350
- $1,750
|
$
|
2,655
- $3,445
|
||||
UE
|
60
|
365
- 505
|
750
- 1,040
|
1,175
- 1,605
|
||||||||
Genco
|
10
|
555
- 720
|
305
- 320
|
870
-
1,050
|
||||||||
CILCO
|
5
|
260 -
330
|
145
- 200
|
410
- 535
|
||||||||
EEI
|
5
|
55
- 75
|
190
- 235
|
250
- 315
|
The
states of Illinois and Missouri must also develop attainment plans to meet
the
federal 8-hour ozone ambient standard by June 2007 and the federal fine
particulate ambient standard by April 2008. The costs reflected in the table
assume that emission controls required for the Clean Air Interstate Rule
regulations will be sufficient to meet this new standard in the St. Louis
region. Should Missouri develop an
48
alternative
plan to comply with this standard, the cost impact could be material to UE.
Illinois is planning to impose additional requirements beyond the Clean Air
Interstate Rule as part of the attainment plans for ozone and fine particulate.
At this time, we are unable to determine the impact state actions would have
on
our results of operations, financial position, or liquidity.
Emission
Credits
Both
federal and state laws require significant reductions in SO2
and
NOx
emissions that result from burning fossil fuels. The Clean Air Act and
NOx
Budget
Trading Program created marketable commodities called allowances. Currently
each
allowance gives the owner the right to emit one ton of SO2
or
NOx.
All
existing generating facilities have been allocated allowances that are based
on
past production and the statutory emission reduction goals. If additional
allowances are needed for new generating facilities, they can be purchased
from
facilities that have excess allowances or from allowance banks. Our generating
facilities comply with the SO2
limits
through the use and purchase of allowances, through the use of low-sulfur fuels,
and through the application of pollution control technology. The NOx
Budget
Trading Program limits emissions of NOx
during
the ozone season (May through September). The NOx
Budget
Trading Program has applied to all electric generating units in Illinois since
the beginning of 2004; it will apply to the eastern third of Missouri, where
UE’s coal-fired power plants are located, beginning in 2007. Our generating
facilities are expected to comply with the NOx
limits
through the use and purchase of allowances or through the application of
pollution control technology, including low-NOx
burners,
over-fire air systems, combustion optimization, rich reagent injection,
selective noncatalytic reduction and selective catalytic reduction
systems.
The
following table presents the tons of SO2
and
NOx
emission
allowances held and the related SO2
and
NOx
book
values that are carried as intangible assets as of September 30,
2006.
SO2 (a)
|
NOx (b)
|
Book
Value
|
|||||||
UE
|
1.816
|
605
|
$
|
63
|
|||||
Genco
|
0.677
|
16,227
|
81
|
||||||
CILCO
|
0.322
|
3,798
|
51
|
||||||
EEI
|
0.300
|
5,594
|
33
|
(a) |
Vintages
are from 2006 to 2016. Each company possesses additional allowances
for
use in periods beyond 2016. Units are in millions of SO2
allowances (currently one allowance equals one ton
emitted).
|
(b) |
Vintages
are from 2006 to 2008. Units are in NOx
allowances (one allowance equals one ton emitted).
|
The
following table presents the distribution by company and year of the
NOx
emission
allowances that were allocated by the Illinois EPA on September 12, 2006 for
2007 and 2008.
2007(a)
|
2008(a)
|
|||||
UE
|
156
|
130
|
||||
Genco
|
4,656
|
4,679
|
||||
CILCO
|
2,052
|
2,053
|
||||
EEI
|
2,746
|
2,713
|
(a) |
These
NOx
allowances are included in the total allowances table
above.
|
Allocations
of NOx
allowances for UE’s Missouri generating facilities will be 10,178 tons per
emissions season in 2007 and 2008. UE, Genco, CILCO and EEI expect to use a
substantial portion of the SO2
and
NOx
allowances for ongoing operations. New environmental regulations, including
the
Clean Air Interstate Rule, the timing of the installation of pollution control
equipment and the level of operations will have a significant impact on the
amount of allowances actually required for ongoing operations. The Clean Air
Interstate Rule requires a reduction in SO2
emissions by requiring a change in the way Acid Rain Program allowances are
surrendered. The current Acid Rain Program requires the surrender of one
SO2
allowance for every ton of SO2
that is
emitted. The Clean Air Interstate Rule program will require that SO2
allowances be surrendered at a ratio of two allowances for every ton of emission
in 2010 through 2014. Beginning in 2015, the Clean Air Interstate Rule program
will require SO2
allowances to be surrendered at a ratio of 2.86 allowances for every ton of
emission.
New
Source Review
The
EPA
has been conducting an enforcement initiative in an effort to determine whether
modifications at a number of coal-fired power plants owned by electric utilities
in the United States are subject to New Source Review requirements or New Source
Performance Standards under the Clean Air Act. The EPA’s inquiries focus on
whether the best available emission control technology was or should have been
used at such power plants when major maintenance or capital improvements were
performed.
In
April
2005, Genco received a request from the EPA for information pursuant to Section
114(a) of the Clean Air Act seeking detailed operating and maintenance history
data with respect to its Meredosia, Hutsonville, Coffeen, and Newton facilities,
EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. All of
these facilities are coal-fired power plants. The information request required
Genco to provide responses to specific EPA questions regarding certain projects
and maintenance activities to determine compliance with certain Illinois air
pollution and emissions rules and with the New Source Performance Standard
requirements of the Clean Air Act. Information responsive to the EPA’s request
has been submitted but we cannot predict the outcome of this
matter.
49
Remediation
We
are
involved in a number of remediation actions to clean up hazardous waste sites
as
required by federal and state law. Such statutes require that responsible
parties fund remediation actions regardless of degree of fault, legality of
original disposal, or ownership of a disposal site. UE, CIPS, CILCO and IP
have
each been identified by the federal or state governments as a potentially
responsible party at several contaminated sites. Several of these sites involve
facilities that were transferred by CIPS to Genco in May 2000 and facilities
transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS
and
CILCO contractually agreed to indemnify Genco and AERG for remediation costs
associated with preexisting environmental contamination at the transferred
sites.
As
of
September 30, 2006, CIPS, CILCO and IP owned or were otherwise responsible
for
14, four and 25 former MGP sites, respectively, in Illinois. All of these sites
are in various stages of investigation, evaluation and remediation. Under its
current schedule, Ameren anticipates that remediation at these sites should
be
completed by 2015. The ICC permits each company to recover remediation and
litigation costs associated with their former MGP sites in Illinois from their
Illinois electric and natural gas utility customers through environmental
adjustment rate riders. To be recoverable, such costs must be prudently and
properly incurred, and costs are subject to annual reconciliation review by
the
ICC. As of September 30, 2006, CIPS, CILCO and IP had recorded liabilities
of
$26 million, $3 million and $65 million, respectively, to represent estimated
minimum obligations.
In
addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri
and
one in Iowa. UE does not currently have a rate rider mechanism in effect in
Missouri that permits remediation costs associated with MGP sites to be
recovered from utility customers. See Note 2 - Rate and Regulatory Matters
for
information on a law enacted in Missouri in 2005 enabling the MoPSC to put
in
place environmental cost recovery mechanisms for Missouri utilities. UE does
not
have any retail utility operations in Iowa that would provide a source of
recovery of these remediation costs. Because of the unknown and unique
characteristics of each site (such as amount and type of residues present,
physical characteristics of the site, and the environmental risk) and uncertain
regulatory requirements, we are not able to determine the maximum liability
for
the remediation of these sites. As of September 30, 2006, UE had recorded $10
million to represent its estimated minimum obligation for MGP sites. UE also
is
responsible for four electric sites in Missouri that have corporate cleanup
liability, most as a result of federal agency mandates. As of September 30,
2006, UE had recorded $5 million to represent its estimated minimum obligation
for these sites. At this time, we are unable to determine what portion of these
costs, if any, will be eligible for recovery from insurance carriers.
In
June
2000, the EPA notified UE and numerous other companies that former landfills
and
lagoons in Sauget, Illinois, may contain soil and groundwater contamination.
These sites are known as Sauget Area 2. From approximately 1926 until 1976,
UE
operated a power generating facility adjacent to Sauget Area 2. UE currently
owns a parcel of property that was used as a landfill. Under the terms of an
Administrative Order and Consent, UE has joined with other potentially
responsible parties to evaluate the extent of potential contamination with
respect to Sauget Area 2.
In
October 2002, UE was included in a Unilateral Administrative Order issued by
the
EPA listing potentially liable parties for groundwater contamination for a
portion of the Sauget Area 2 site. The Unilateral Administrative Order
encompasses the groundwater contamination releasing to the Mississippi River
adjacent to Solutia’s former chemical waste landfill and the resulting impact
area in the Mississippi River. UE was asked to participate in response to
activities that involve the installation of a barrier wall around a chemical
waste site and three recovery wells to divert groundwater flow. The projected
cost for this remedy method ranges from $25 million to $30 million. In November
2002, UE sent a letter to the EPA asserting its defenses to the Unilateral
Administrative Order and requesting its removal from the list of potentially
responsible parties under the Unilateral Administrative Order. Solutia agreed
to
comply with the Unilateral Administrative Order. However, in December 2003,
Solutia filed for bankruptcy protection and it is now seeking to discharge
its
environmental liabilities. In March 2004, Pharmacia Corporation, the former
parent company of Solutia, confirmed its intent to comply with the EPA’s
Unilateral Administrative Order.
The
status of future remediation at Sauget Area 2 and compliance with the Unilateral
Administrative Order is uncertain, so we are unable to predict the ultimate
impact of the Sauget Area 2 site on our results of operations, financial
position, or liquidity. In December 2004, the U.S. Supreme Court, in Cooper
Industries, Inc., vs. Aviall Services, Inc., limited the circumstances under
which potentially responsible parties could assert cost-recovery claims against
other potentially responsible parties. As a result of this ruling, it is
possible that UE may not be able to recover from other potentially responsible
parties the costs it incurs in complying with EPA orders. Any liability or
responsibility that may be imposed on UE as a result of this Sauget, Illinois,
environmental matter was not transferred to CIPS as a part of UE’s May 2005
Illinois utility service territory transfer to CIPS.
In
December 2004, AERG submitted a comprehensive package to the Illinois EPA to
address groundwater and surface water issues associated with the recycle pond,
ash
50
ponds,
and reservoir at the Duck Creek power plant facility. Information submitted
by
AERG is currently under review by the Illinois EPA. CILCORP and CILCO both
have
a liability of $3 million at September 30, 2006, included on their Consolidated
Balance Sheets for the estimated cost of the remediation effort, which involves
treating and discharging recycle-system water in order to address these
groundwater and surface water issues.
In
addition, our operations, or those of our predecessor companies, involve the
use, disposal and, in appropriate circumstances, the cleanup of substances
regulated under environmental protection laws. We are unable to determine the
impact these activities may have on our results of operations, financial
position, or liquidity.
Pumped-storage
Hydroelectric Facility Breach
In
December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk
pumped-storage hydroelectric facility. This resulted in significant flooding
in
the local area, which damaged a state park. Reports issued by outside experts
hired by UE to review the cause of the incident and by FERC staff indicate
design, construction and human error as causes of the breach. In their report,
UE’s outside experts concluded that restoration of the upper reservoir, if
undertaken, will require a complete rebuild of the entire dam with a completely
different design concept, not simply a repair of the breached area.
The
FERC
investigation of the incident has been completed. In October 2006, the FERC
approved a stipulation and consent agreement between UE and the FERC’s Office of
Enforcement that resolves all issues arising from an investigation that the
FERC’s Office of Enforcement conducted into alleged violations of license
conditions and FERC regulations by UE as the licensee of the Taum Sauk
hydroelectric facility that may have contributed to the breach of the upper
reservoir. As part of the stipulation and consent agreement, UE agreed, among
other things, to: (i) pay a civil penalty of $10 million; (ii) pay $5 million
into an interest-bearing escrow account to fund project enhancements at or
near
the Taum Sauk facility; and (iii) implement and comply with a new dam safety
program developed in connection with the settlement. As a result of $8 million
having previously been accrued with respect to the FERC’s investigation in the
second quarter of 2006, UE’s after-tax charge to earnings in the third quarter
ended September 30, 2006, related to this stipulation and consent agreement
was
limited to $7 million.
Investigations
by state authorities of the incident have not concluded. The facility will
remain out of service until reviews by state authorities are concluded, further
analyses are completed, and input is received from key stakeholders as to how
and whether to rebuild the facility. Should the decision be made to rebuild
the
Taum Sauk plant, UE would expect it to be out of service through at least all
of
2008, if not longer.
UE
has
accepted responsibility for the effects of the incident. At this time, UE
believes that substantially all of the damage and liabilities caused by the
breach, including rebuilding the plant, will be covered by insurance. UE expects
the total cost for damage and liabilities, excluding costs to rebuild the
facility, resulting from the Taum Sauk incident to range from $106 million
to
$126 million. As of September 30, 2006, UE had paid $38 million and accrued
a
$68 million liability, including costs resulting from the FERC stipulation
and
consent discussed above, while expensing $18 million and recording an $88
million receivable due from insurance companies. As of September 30, 2006,
UE
has received $12 million from insurance companies reducing the insurance
receivable balance to $76 million. No amounts have been recognized in the
financial statements relating to estimated costs to repair or rebuild the
facility. Under UE’s insurance policies, all claims by or against UE are subject
to review by its insurance carriers.
As
a
result of this breach, UE may be subject to litigation by private parties or
by
state authorities. Until the reviews conducted by state authorities have
concluded, the insurance review is completed, a decision whether the plant
will
be rebuilt is made, and future regulatory treatment for the plant is determined,
among other things, we are unable to determine the impact the breach may have
on
Ameren’s and UE’s results of operations, financial position, or liquidity beyond
those amounts already recognized.
Asbestos-related
Litigation
Ameren,
UE, CIPS, Genco, CILCO and IP have been named, along with numerous other
parties, in a number of lawsuits filed by plaintiffs claiming varying degrees
of
injury from asbestos exposure. Most have been filed in the Circuit Court of
Madison County, Illinois. The total number of defendants named in each case
is
significant; as many as 185 parties are named in some pending cases and as
few
as six in others. However, in the cases that were pending as of September 30,
2006, the average number of parties is 67.
The
claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from
asbestos exposure during the plaintiffs’ activities at our present or former
electric generating plants. Former CIPS plants are now owned by Genco, and
most
former CILCO plants are now owned by AERG. Most of IP’s plants were transferred
to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the
transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO
contractually agreed to indemnify Genco and AERG for liabilities associated
with
asbestos-related claims arising from activities prior to the transfer. Each
lawsuit seeks unspecified damages in excess of $50,000, which, if proved,
typically would be shared among the named defendants.
51
From
July
1, 2006, through September 30, 2006, six additional asbestos-related lawsuits
were filed against Ameren, UE, CIPS, CILCO and IP, mostly in the Circuit Court
of Madison County, Illinois. Two lawsuits were dismissed and five were settled.
The following table presents the status as of September 30, 2006, of the
asbestos-related lawsuits that have been filed against the Ameren
Companies:
Specifically
Named as Defendant
|
|||||||||||||||||||||
Total(a)
|
Ameren
|
UE
|
CIPS
|
Genco
|
CILCO
|
IP
|
|||||||||||||||
Filed
|
316
|
31
|
170
|
130
|
2
|
39
|
150
|
||||||||||||||
Settled
|
100
|
-
|
51
|
43
|
-
|
11
|
50
|
||||||||||||||
Dismissed
|
145
|
24
|
93
|
47
|
2
|
6
|
65
|
||||||||||||||
Pending
|
71
|
7
|
26
|
40
|
-
|
22
|
35
|
(a) |
Addition
of the numbers in the individual columns does not equal the total
column
because some of the lawsuits name multiple Ameren entities as defendants.
|
As
of
September 30, 2006, five asbestos-related lawsuits were pending against EEI.
The
general liability insurance maintained by EEI provides coverage with respect
to
liabilities arising from asbestos-related claims.
The
Ameren Companies believe that the final disposition of these proceedings will
not have a material adverse effect on their results of operations, financial
position, or liquidity.
The
ICC
order approving Ameren’s acquisition of IP effective September 30, 2004, also
approved a tariff rider to recover the costs of IP’s asbestos-related litigation
claims, subject to the following terms. Beginning in 2007, 90% of cash
expenditures in excess of the amount included in base electric rates will be
paid for by IP from a $20 million trust fund established by IP and financed
with
contributions of $10 million each by Ameren and Dynegy. If cash expenditures
are
less than the amount in base rates, IP will contribute 90% of the difference
to
the fund. Once the trust fund is depleted, 90% of allowed cash expenditures
in
excess of base rates will be recovered through charges assessed to customers
under the tariff rider.
NOTE
9 - CALLAWAY NUCLEAR PLANT
Under
the
Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent
storage and disposal of spent nuclear fuel. The DOE currently charges one mill,
or 1/10
of one
cent, per nuclear-generated kilowatthour sold for future disposal of spent
fuel.
Pursuant to this act, UE collects one mill from its electric customers for
each
kilowatthour of electricity that it generates and sells from its Callaway
nuclear plant. Electric utility rates charged to customers provide for recovery
of such costs. The DOE is not expected to have its permanent storage facility
for spent fuel available until at least 2017. UE has sufficient installed
storage capacity at its Callaway nuclear plant until 2020. It has the capability
for additional storage capacity through the licensed life of the plant. The
delayed availability of the DOE’s disposal facility is not expected to adversely
affect the continued operation of the Callaway nuclear plant through its
currently licensed life.
Electric
utility rates charged to customers provide for the recovery of the Callaway
nuclear plant’s decommissioning costs, which include decontamination,
dismantling, and site restoration costs, over an assumed 40-year life of the
plant, ending with the expiration of the plant’s operating license in 2024. It
is assumed that the Callaway nuclear plant site will be
decommissioned
based on immediate dismantlement method and removal from service. Ameren and
UE
have recorded an ARO for the Callaway nuclear plant decommissioning costs at
fair value, which represents the present value of estimated future cash
outflows. Decommissioning costs are charged to the costs of service used to
establish electric rates for UE’s customers. These costs amounted to $7 million
in each of the years 2005, 2004 and 2003. Every three years, the MoPSC requires
UE to file an updated cost study for decommissioning its Callaway nuclear plant.
Electric rates may be adjusted at such times to reflect changed estimates.
The
latest study was filed in 2005. Discovery of tritium releases in 2006 at the
Callaway nuclear plant may result in an increased estimate for decommissioning
when the next study is conducted. Costs collected from customers are deposited
in an external trust fund to provide for the Callaway nuclear plant’s
decommissioning. If the assumed return on trust assets is not earned, we believe
that it is probable that any such earnings deficiency will be recovered in
rates. The fair value of the nuclear decommissioning trust fund for UE’s
Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in
Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally
restricted. It may be used only to fund the costs of nuclear decommissioning.
Changes in the fair value of the trust fund are recorded as an increase or
decrease to the nuclear decommissioning trust fund and to a regulatory asset.
52
NOTE
10 - OTHER
COMPREHENSIVE INCOME
Comprehensive
income includes net income as reported on the statements of income and all
other
changes in common stockholders’ equity, except those resulting from transactions
with common shareholders. A reconciliation of net income to comprehensive income
for the three months and nine months ended September 30, 2006 and 2005, is
shown
below for the Ameren Companies:
Three
Months
|
Nine
Months
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
Ameren:(a)
|
|||||||||||||
Net
income
|
$
|
293
|
$
|
280
|
$
|
486
|
$
|
586
|
|||||
Unrealized
gain on derivative hedging instruments, net of taxes of $12, $11,
$9
and $22, respectively
|
23
|
15
|
19
|
33
|
|||||||||
Reclassification
adjustments for (gains) included in net income, net of taxes of $6,
$2,
$11 and $3, respectively
|
(10
|
)
|
(2
|
)
|
(18
|
)
|
(5
|
)
|
|||||
Total
comprehensive income, net of taxes
|
$
|
306
|
$
|
293
|
$
|
487
|
$
|
614
|
|||||
UE:
|
|||||||||||||
Net
income
|
$
|
166
|
$
|
164
|
$
|
309
|
$
|
353
|
|||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$3,
$(2), $2 and $ -, respectively
|
4
|
(4
|
)
|
3
|
(1
|
)
|
|||||||
Reclassification
adjustments for (gains) included in net income, net of taxes
of $1, $
-, $2 and $ -, respectively
|
(1
|
)
|
(1
|
)
|
(3
|
)
|
(1
|
)
|
|||||
Total
comprehensive income, net of taxes
|
$
|
169
|
$
|
159
|
$
|
309
|
$
|
351
|
|||||
CIPS:
|
|||||||||||||
Net
income
|
$
|
29
|
$
|
31
|
$
|
43
|
$
|
46
|
|||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$
-, $4, $(1) and $7, respectively
|
-
|
7
|
(2
|
)
|
11
|
||||||||
Reclassification
adjustments for (gains) included in net income, net of taxes
of $1, $1,
$3 and $1, respectively
|
(1
|
)
|
(1
|
)
|
(4
|
)
|
(2
|
)
|
|||||
Total
comprehensive income, net of taxes
|
$
|
28
|
37
|
$
|
37
|
$
|
55
|
||||||
Genco:
|
|||||||||||||
Net
income
|
$
|
19
|
$
|
32
|
$
|
27
|
$
|
94
|
|||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$1, $(3), $1 and $(3), respectively
|
1
|
(5
|
)
|
2
|
(6
|
)
|
|||||||
Total
comprehensive income, net of taxes
|
$
|
20
|
$
|
27
|
$
|
29
|
$
|
88
|
|||||
CILCORP:
|
|||||||||||||
Net
income
|
$
|
13
|
$
|
5
|
$
|
22
|
$
|
16
|
|||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$1,
$13, $(6) and $19, respectively
|
2
|
19
|
(10
|
)
|
31
|
||||||||
Reclassification
adjustments for (gains) included in net income, net of taxes of $4,
$ -,
$7 and $ -, respectively
|
(6
|
)
|
(1
|
)
|
(10
|
)
|
-
|
||||||
Total
comprehensive income, net of taxes
|
$
|
9
|
$
|
23
|
$
|
2
|
$
|
47
|
|||||
CILCO:
|
|||||||||||||
Net
income
|
$
|
19
|
$
|
11
|
$
|
44
|
$
|
37
|
|||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$1,
$13, $(6), and $20, respectively
|
2
|
19
|
(9
|
)
|
30
|
||||||||
Reclassification
adjustments for (gains) included in net income, net of taxes
of $4,
$
-, $7 and $1, respectively
|
(6
|
)
|
(1
|
)
|
(10
|
)
|
(1
|
)
|
|||||
Total
comprehensive income, net of taxes
|
$
|
15
|
$
|
29
|
$
|
25
|
$
|
66
|
|||||
IP:
|
|||||||||||||
Net
income
|
$
|
43
|
$
|
54
|
$
|
63
|
$
|
91
|
|||||
Unrealized
(loss) on derivative hedging instruments, net of (benefit) of $
-,
$
-, $ - and $ -, respectively
|
-
|
-
|
(1
|
)
|
-
|
||||||||
Reclassification
adjustments for losses included in net income, net of (benefit)
of
$ -, $ -, $(1) and $ -, respectively
|
-
|
-
|
1
|
-
|
|||||||||
Total
comprehensive income, net of taxes
|
$
|
43
|
$
|
54
|
$
|
63
|
$
|
91
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
NOTE
11 -
RETIREMENT BENEFITS
Ameren’s
pension plans are funded in compliance with income tax regulations and federal
funding requirements. Based on the new contribution requirements in the recently
passed Pension Protection Act of 2006, in order to maintain minimum funding
levels for Ameren’s pension plans, we do not expect future contributions to be
required until 2009 at which time we would expect a required contribution of
$100 million to $150 million. Required contributions of $150 million to $200
million each year are also
53
expected
for 2010 and 2011. These amounts are estimates and may change with actual stock
market performance, changes in interest rates, any pertinent changes in
government regulations, and any voluntary contributions.
The
following tables present the components of the net periodic benefit cost for
our
pension and postretirement benefit plans for the three months and nine months
ended September 30, 2006 and 2005:
Pension
Benefits(a)
|
||||||||||||
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Service
cost
|
$
|
16
|
$
|
14
|
$
|
47
|
$
|
43
|
||||
Interest
cost
|
43
|
41
|
129
|
124
|
||||||||
Expected
return on plan assets
|
(49
|
)
|
(45
|
)
|
(147
|
)
|
(136
|
)
|
||||
Amortization
of:
|
||||||||||||
Prior
service cost
|
3
|
3
|
8
|
8
|
||||||||
Actuarial
loss
|
10
|
9
|
31
|
28
|
||||||||
Net
periodic benefit cost
|
$
|
23
|
$
|
22
|
$
|
68
|
$
|
67
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant
subsidiaries.
|
Postretirement
Benefits(a)
|
||||||||||||
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Service
cost
|
$
|
5
|
$
|
5
|
$
|
16
|
$
|
16
|
||||
Interest
cost
|
18
|
17
|
51
|
53
|
||||||||
Expected
return on plan assets
|
(12
|
)
|
(11
|
)
|
(35
|
)
|
(34
|
)
|
||||
Amortization
of:
|
||||||||||||
Transition
obligation
|
-
|
1
|
1
|
2
|
||||||||
Prior
service cost
|
(2
|
)
|
(2
|
)
|
(5
|
)
|
(4
|
)
|
||||
Actuarial
loss
|
9
|
9
|
26
|
28
|
||||||||
Net
periodic benefit cost
|
$
|
18
|
$
|
19
|
$
|
54
|
$
|
61
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant
subsidiaries.
|
UE,
CIPS,
Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are
responsible for their proportionate share of the pension and postretirement
costs. The following tables present the pension costs and the postretirement
benefit costs incurred for the three months and nine months ended September
30,
2006 and 2005:
Pension
Costs
|
||||||||||||
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
UE
|
$
|
13
|
$
|
13
|
$
|
39
|
$
|
39
|
||||
CIPS
|
3
|
3
|
9
|
9
|
||||||||
Genco
|
2
|
2
|
6
|
6
|
||||||||
CILCORP
|
3
|
3
|
8
|
9
|
||||||||
CILCO
|
4
|
5
|
11
|
14
|
||||||||
IP
|
2
|
1
|
6
|
4
|
Postretirement
Costs
|
||||||||||||
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
UE
|
$
|
9
|
$
|
11
|
$
|
28
|
$
|
33
|
||||
CIPS
|
2
|
2
|
6
|
8
|
||||||||
Genco
|
1
|
1
|
3
|
3
|
||||||||
CILCORP
|
3
|
2
|
7
|
8
|
||||||||
CILCO
|
4
|
3
|
11
|
12
|
||||||||
IP
|
3
|
3
|
10
|
9
|
NOTE
12 - SEGMENT
INFORMATION
Prior
to
the third quarter of 2006, Ameren reported one segment, Utility Operations,
comprising electric generation and electric and gas transmission and
distribution operations, with Other including Ameren holding company activity.
As a result of the following changes in circumstances, Ameren, UE, CILCORP
and CILCO changed their segments in the third quarter of 2006:
· |
the
Ameren Companies’ chief operating decision-making group began to
assess performance and allocate resources based on a new segment
structure and made
|
54
related
organizational and management reporting changes
in the third quarter of 2006;
· |
electric
generation deregulation in Illinois, which is currently scheduled
to
become effective January 1, 2007;
|
· |
the
expiration of affiliate power supply agreements for CIPS and CILCO,
and
other supply agreements for IP on December 31,
2006;
|
· |
the
July 2006 termination of the JDA among UE, Genco and CIPS effective
December 31, 2006; and
|
· |
the
September 2006 completion of a state-wide auction to procure power
for
CIPS, CILCO and IP for 2007 and beyond, Marketing Company's sale
in that
auction of power being acquired from Genco and
AERG.
|
Ameren
determined in the third quarter of 2006 that it has three reportable segments:
Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The
Missouri Regulated segment for Ameren includes all the operations of UE’s
business as described in Note 1 - Summary of Significant Accounting Policies,
except for UE’s 40% interest in EEI and other non-rate regulated activities,
which are included in Other. The Illinois Regulated segment for Ameren consists
of the regulated electric and gas transmission and distribution businesses
of
CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting
Policies. The Non-rate-regulated Generation segment for Ameren primarily
consists of the operations or activities of Genco, the CILCORP holding company,
AERG, EEI, and Marketing Company. Other primarily includes Ameren holding
company activities and the leasing activities of CILCORP, AERG, Resources
Company, and CIPSCO Investment Company.
UE
determined it now has one reportable segment: Missouri Regulated. The Missouri
Regulated segment for UE includes all the operations of UE’s business as
described in Note 1 - Summary of Significant Accounting Policies, except for
UE’s 40% interest in EEI and other non-rate-regulated activities, which are
included in Other.
CILCORP
and CILCO determined they now have two reportable segments: Illinois Regulated
and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP
and CILCO is comprised of the regulated electric and gas transmission and
distribution businesses of CILCO. The Non-rate-regulated Generation segment
for
CILCORP and CILCO consists of the generation business of AERG. Other for CILCORP
and CILCO is comprised of leveraged lease investments, parent company activity,
and minor activities not reported in the Illinois Regulated or
Non-rate-regulated Generation segments for CILCORP.
Prior
period presentation has been adjusted for comparative purposes.
The
following table presents information about the reported revenues and net income
of Ameren for the three months and nine months ended September 30, 2006 and
2005, and total assets as of September 30, 2006 and December 31, 2005.
Three
Months
|
Missouri
Regulated
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
Other
|
Intersegment
Eliminations
|
Consolidated
|
||||||||||||
2006:
|
||||||||||||||||||
External
revenues
|
$
|
813
|
$
|
836
|
$
|
261
|
$
|
-
|
$
|
-
|
$
|
1,910
|
||||||
Intersegment
revenues
|
44
|
7
|
212
|
-
|
(263
|
)
|
-
|
|||||||||||
Net
income(a)
|
142
|
83
|
61
|
7
|
-
|
293
|
||||||||||||
2005:
|
||||||||||||||||||
External
revenues
|
$
|
828
|
$
|
835
|
$
|
217
|
$
|
1
|
$
|
-
|
$
|
1,881
|
||||||
Intersegment
revenues
|
67
|
11
|
246
|
-
|
(324
|
)
|
-
|
|||||||||||
Net
income(a)
|
162
|
96
|
27
|
(5
|
)
|
-
|
280
|
|||||||||||
Nine
Months
|
||||||||||||||||||
2006:
|
||||||||||||||||||
External
revenues
|
$
|
2,024
|
$
|
2,501
|
$
|
735
|
$
|
-
|
$
|
-
|
$
|
5,260
|
||||||
Intersegment
revenues
|
179
|
17
|
603
|
-
|
(799
|
)
|
-
|
|||||||||||
Net
income(a)
|
258
|
125
|
100
|
3
|
-
|
486
|
||||||||||||
2005:
|
||||||||||||||||||
External
revenues
|
$
|
2,075
|
$
|
2,338
|
$
|
659
|
$
|
7
|
$
|
-
|
$
|
5,079
|
||||||
Intersegment
revenues
|
179
|
30
|
640
|
-
|
(849
|
)
|
-
|
|||||||||||
Net
income(a)
|
346
|
159
|
89
|
(8
|
)
|
-
|
586
|
|||||||||||
As
of September 30, 2006:
|
||||||||||||||||||
Total
assets
|
$
|
9,910
|
$
|
5,986
|
$
|
3,650
|
$
|
1,813
|
$
|
(2,529
|
)
|
$
|
18,830
|
|||||
As
of December 31, 2005:
|
||||||||||||||||||
Total
assets
|
9,261
|
6,073
|
3,731
|
1,949
|
(2,852
|
)
|
18,162
|
(a) |
Represents
net income available to common shareholders; 100% of CILCO’s preferred
stock dividends are included in the Illinois Regulated
segment.
|
55
The
following table presents information about the reported revenues and net
income
of UE for the three months and nine months ended September 30, 2006 and 2005,
and total assets as of September 30, 2006 and December 31, 2005.
Three
Months
|
Missouri
Regulated
|
Other
(a)
|
Consolidated
UE
|
||||||
2006:
|
|||||||||
Revenues
|
$
|
857
|
$
|
-
|
$
|
857
|
|||
Net
income(b)
|
142
|
23
|
165
|
||||||
2005:
|
|||||||||
Revenues
|
$
|
895
|
$
|
-
|
$
|
895
|
|||
Net
income(b)
|
162
|
1
|
163
|
||||||
Nine
Months
|
|||||||||
2006:
|
|||||||||
Revenues
|
$
|
2,203
|
$
|
-
|
$
|
2,203
|
|||
Net
income(b)
|
258
|
47
|
305
|
||||||
2005:
|
|||||||||
Revenues
|
$
|
2,254
|
$
|
-
|
$
|
2,254
|
|||
Net
income(b)
|
346
|
3
|
349
|
||||||
As
of September 30, 2006:
|
|||||||||
Total
assets
|
$
|
9,910
|
$
|
24
|
$
|
9,934
|
|||
As
of December 31, 2005:
|
|||||||||
Total
assets
|
9,261
|
16
|
9,277
|
(a) |
Includes
40% interest in EEI and other non-rate-regulated
activities.
|
(b) |
Represents
net income available to the common shareholder
(Ameren).
|
The
following table presents information about the reported revenues and net
income
of CILCORP for the three months and nine months ended September 30, 2006
and
2005, and total assets as of September 30, 2006 and December 31,
2005.
Three
Months
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
CILCORP
Other
|
Intersegment
Eliminations
|
Consolidated
CILCORP
|
||||||||||
2006:
|
|||||||||||||||
External
revenues
|
$
|
154
|
$
|
3
|
$
|
1
|
$
|
-
|
$
|
158
|
|||||
Intersegment
revenues
|
-
|
56
|
-
|
(56
|
)
|
-
|
|||||||||
Net
income(a)
|
11
|
2
|
-
|
-
|
13
|
||||||||||
2005:
|
|||||||||||||||
External
revenues
|
$
|
159
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
159
|
|||||
Intersegment
revenues
|
-
|
54
|
-
|
(54
|
)
|
-
|
|||||||||
Net
income(a)
|
12
|
(8
|
)
|
1
|
-
|
5
|
|||||||||
Nine
Months
|
|||||||||||||||
2006:
|
|||||||||||||||
External
revenues
|
$
|
523
|
$
|
23
|
$
|
-
|
$
|
-
|
$
|
546
|
|||||
Intersegment
revenues
|
-
|
139
|
-
|
(139
|
)
|
-
|
|||||||||
Net
income(a)
|
22
|
4
|
(4
|
)
|
-
|
22
|
|||||||||
2005:
|
|||||||||||||||
External
revenues
|
$
|
498
|
$
|
24
|
$
|
6
|
$
|
-
|
$
|
528
|
|||||
Intersegment
revenues
|
-
|
140
|
-
|
(140
|
)
|
-
|
|||||||||
Net
income(a)
|
26
|
(12
|
)
|
2
|
-
|
16
|
|||||||||
As
of September 30, 2006:
|
|||||||||||||||
Total
assets(b)
|
$
|
1,169
|
$
|
1,157
|
$
|
4
|
$
|
(226
|
)
|
$
|
2,104
|
||||
As
of December 31, 2005:
|
|||||||||||||||
Total
assets(b)
|
1,231
|
1,201
|
4
|
(202
|
)
|
2,234
|
(a) |
Represents
net income available to the common shareholders (Ameren); 100% of
CILCO’s
preferred stock dividends are included in the Illinois Regulated
segment.
|
(b) |
Total
assets for Illinois Regulated include an allocation of goodwill and
other
purchase accounting amounts related to CILCO that are recorded at
CILCORP
(parent company).
|
56
The
following table presents information about the reported revenues and net income
of CILCO for the three months and nine months ended September 30, 2006 and
2005,
and total assets as of September 30, 2006 and December 31, 2005.
Three
Months
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
CILCO
Other
|
Intersegment
Eliminations
|
Consolidated
CILCO
|
||||||||||
2006:
|
|||||||||||||||
External
revenues
|
$
|
154
|
$
|
3
|
$
|
-
|
$
|
-
|
$
|
157
|
|||||
Intersegment
revenues
|
-
|
56
|
-
|
(56
|
)
|
-
|
|||||||||
Net
income(a)
|
11
|
8
|
-
|
-
|
19
|
||||||||||
2005:
|
|||||||||||||||
External
revenues
|
$
|
159
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
159
|
|||||
Intersegment
revenues
|
-
|
54
|
-
|
(54
|
)
|
-
|
|||||||||
Net
income(a)
|
12
|
(2
|
)
|
-
|
-
|
10
|
|||||||||
Nine
Months
|
|||||||||||||||
2006:
|
|||||||||||||||
External
revenues
|
$
|
523
|
$
|
23
|
$
|
-
|
$
|
-
|
$
|
546
|
|||||
Intersegment
revenues
|
-
|
139
|
-
|
(139
|
)
|
-
|
|||||||||
Net
income(a)
|
22
|
24
|
(3
|
)
|
-
|
43
|
|||||||||
2005:
|
|||||||||||||||
External
revenues
|
$
|
498
|
$
|
24
|
$
|
-
|
$
|
-
|
$
|
522
|
|||||
Intersegment
revenues
|
-
|
140
|
-
|
(140
|
)
|
-
|
|||||||||
Net
income(a)
|
26
|
9
|
-
|
-
|
35
|
||||||||||
As
of September 30, 2006:
|
|||||||||||||||
Total
assets
|
$
|
949
|
$
|
565
|
$
|
1
|
$
|
(17
|
)
|
$
|
1,498
|
||||
As
of December 31, 2005:
|
|||||||||||||||
Total
assets
|
1,008
|
563
|
1
|
(15
|
)
|
1,557
|
(a) |
Represents
net income available to the common shareholder (CILCORP); 100% of
CILCO’s
preferred stock dividends are included in the Illinois Regulated
segment.
|
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
OVERVIEW
Ameren
Executive Summary
Ameren’s
earnings in 2006 have been significantly impacted by
higher
fuel and transportation costs due primarily to increased coal and related
transportation costs, severe storm-related customer outages, an unplanned outage
at UE’s Callaway nuclear plant and milder winter and summer weather than 2005.
In addition, Ameren incurred additional costs of operating in the MISO Day
Two
Energy Market in the first nine months of 2006 because MISO Day Two operations
did not commence until the second quarter last year. However, the costs of
MISO
Day Two operations in the third quarter of 2006 were lower than the year-ago
period. Incremental costs resulting from the December 2005 breach of the upper
reservoir at UE’s Taum Sauk hydroelectric pumped-storage plant also negatively
impacted earnings in the third quarter and first nine months of 2006. In the
third quarter, UE settled issues relating to the reservoir breach with federal
authorities, but the breach is still being investigated by state authorities.
Increased margins from interchange sales and organic growth compared to the
third quarter and first nine months of last year positively influenced 2006
earnings.
In
Illinois, there has been significant regulatory and legislative activity as
we
approach the scheduled end of a 10-year electric rate freeze and the expiration
of power supply contracts. In electric delivery service rate filings made in
December 2005, CIPS, CILCO and IP requested a total combined annual electric
revenue increase of approximately $200 million. In early October, the
administrative law judges in our delivery service cases recommended an aggregate
$147 million increase in electric rates. The ICC has until late November to
render a decision in these cases.
Since
the
Ameren Illinois utilities own almost no generation and their supply contracts
expire at the end of this year, in September, an ICC-approved procurement
auction for post-2006 power requirements for these companies was held. The
supply contracts from this auction resulted in market prices for power which
are
above those prices currently reflected in customer rates. Due to potential
Illinois rate increases of 40% to 55% there have been calls by some key
lawmakers, including the Illinois governor, for a three-year extension of the
rate freeze in Illinois. We believe an extension of the rate freeze is without
legal merit, and any decision or action that impairs CIPS’, CILCO’s and IP’s
ability to fully recover purchased power or other costs from their electric
customers in a timely manner could result in material adverse consequences
for
all of the Ameren Companies. If an extension of the rate freeze were to occur,
the Ameren Illinois utilities estimate they would spend approximately $1 billion
more annually for power than they could charge their customers. As has been
clearly demonstrated by recent actions and statements by the credit rating
agencies, if the electric rate freeze in Illinois is extended, the credit
ratings of the Ameren Illinois utilities and CILCORP will be slashed
to
57
deep
junk
status. These credit ratings will immediately trigger collateral and other
funding requirements. We believe such funding requirements, combined with the
inability to recover costs through rates to customers, would cause the Ameren
Illinois utilities to exhaust their available cash and credit and be unable
to
borrow. Ameren believes this would lead to the Ameren Illinois utilities and
CILCORP being financially insolvent by February 2007, or sooner. Any decision
or
action that impairs the ability of CIPS, CILCO, and IP to fully recover costs
from their electric customers in a timely manner would result in material
adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCO
and
IP remain steadfastly committed to working with key stakeholders to develop
a
constructive solution that would mitigate the impact of these rate increases
on
our Illinois residential customers, yet still provide for full and timely
recovery of costs. This year the Ameren Illinois utilities filed two different
plans with the ICC that would allow expected electric rate increases to be
phased in over time. These utilities are hopeful that these plans will provide
a
constructive solution to lessen the impact of the expected rate increases on
Illinois customers.
In
early
July 2006, UE filed requests with the MoPSC to increase base rates for electric
service by $361 million and to increase base rates for gas service by $11
million. The primary drivers of the requested electric rate increase were
significant investments in critical energy infrastructure, as well as
significantly higher operating expenses. In conjunction with the filing of
the
electric rate case in Missouri, UE, CIPS and Genco mutually agreed to terminate
the JDA on December 31, 2006. A decision from the MoPSC on both rate case
filings is expected no later than June 2007. The resolution of these regulatory
matters in Illinois and Missouri will have a significant impact on earnings
for
the Ameren Companies in 2007 and beyond.
General
Ameren,
headquartered in St. Louis, Missouri, is a public utility holding company under
PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public
utility holding company under PUHCA 1935, until that act was repealed effective
February 8, 2006. Ameren’s primary asset is the common stock of its
subsidiaries. Ameren’s subsidiaries, which are separate, independent legal
entities with separate businesses, assets and liabilities, operate
rate-regulated electric generation, transmission and distribution businesses,
rate-regulated natural gas transmission and distribution businesses and
non-rate-regulated electric generation businesses in Missouri and Illinois,
as
discussed below. Dividends on Ameren’s common stock depend on distributions made
to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. See
Note 1 - Summary of Significant Accounting Policies to our financial statements
under Part I, Item 1, of this report for a detailed description of our principal
subsidiaries.
· |
UE
operates a rate-regulated electric generation, transmission and
distribution business, and a rate-regulated natural gas transmission
and
distribution business in Missouri. Before May 2, 2005, UE also operated
those businesses in Illinois.
|
· |
CIPS
operates a rate-regulated electric and natural gas transmission and
distribution business in Illinois.
|
· |
Genco
operates a non-rate-regulated electric generation business in Illinois
and
Missouri.
|
· |
CILCO,
a subsidiary of CILCORP (a holding company), operates a rate-regulated
electric and natural gas transmission and distribution business and
a
primarily non-rate-regulated electric generation business (through
its
subsidiary, AERG) in Illinois.
|
· |
IP
operates a rate-regulated electric and natural gas transmission and
distribution business in Illinois.
|
In
addition to presenting results of operations and earnings amounts in total,
we
present certain information in cents per share. These amounts reflect factors
that directly affect Ameren’s earnings. We believe this per share information
helps readers to understand the impact of these factors on Ameren’s earnings per
share. All references in this report to earnings per share are based on
weighted-average diluted common shares outstanding during the applicable period.
All tabular dollar amounts are in millions, unless otherwise
indicated.
Earnings
Summary
Our
results of operations and financial position are affected by many factors.
Weather, economic conditions, and the actions of key customers or competitors
can significantly affect the demand for our services. Our results are also
affected by seasonal fluctuations: winter heating and summer cooling demands.
Approximately 85% of Ameren’s 2005 revenues were directly subject to state and
federal regulation. This regulation can have a material impact on the price
we
charge for our services. Non-rate-regulated sales are subject to market
conditions for power and with the expiration of Genco’s and AERG’s supply
contracts with CIPS and CILCO at the end of 2006, these companies’ and Ameren’s
earnings will be subject to increased volatility. We principally use coal,
nuclear fuel, natural gas, and oil in our operations. The prices for these
commodities can fluctuate significantly due to the global economic and political
environment, weather, supply and demand, and many other factors. We do not
currently have
fuel
or purchased power cost recovery mechanisms in Missouri or Illinois for our
electric utility businesses, but
we do
have gas cost recovery mechanisms in each state for our gas delivery businesses.
In September 2006, the MoPSC approved rules for a fuel and purchased power
cost
recovery mechanism, which are expected to become effective by the end of 2006.
UE has requested approval of a fuel and purchased power cost recovery mechanism
as a part of its
58
current
electric rate case. Since rates for UE, CIPS, CILCO and IP are regulated, cost
decreases or increases will not be immediately reflected in rates. Fluctuations
in interest rates affect our cost of borrowing and our pension and
postretirement benefits costs. We employ various risk management strategies
including the forward sale of power and purchase of fuel to reduce our exposure
to the volatility of commodities and other risks inherent in our businesses.
The
reliability of our power plants and transmission and distribution systems,
the
level of purchased power costs, operating and administrative costs, and capital
investment are key factors that we seek to control to optimize our results
of
operations,
financial position, and liquidity.
Ameren’s
net income increased to $293 million, or $1.42 per share, in the third quarter
of 2006 from $280 million, or $1.37 per share, in the third quarter of 2005.
Ameren’s net income decreased to $486 million, or $2.37 per share, for the nine
months ended September 30, 2006, from earnings of $586 million, or $2.94 per
share, in the first nine months of 2005.
Earnings
were negatively impacted for the three-month and nine-month periods by the
costs
and lost electric margins associated with outages caused by severe storms,
lower
prices for interchange sales, milder weather conditions, and costs associated
with an upper reservoir breach in December 2005 at UE’s Taum Sauk plant. In the
third quarter of 2005, we began a scheduled refueling and maintenance outage
at
UE’s Callaway nuclear plant and recorded an impairment of an aircraft leveraged
lease; items that did not recur in 2006. The nine-month period was also
unfavorably impacted by an unscheduled outage at UE’s Callaway nuclear plant in
the second quarter of 2006 and increased fuel and purchased power costs,
including incremental costs of operating in the MISO Day Two Energy Market.
An
increase in the number of common shares outstanding in the current-year periods
further reduced Ameren’s earnings per share. Increased margins on interchange
sales at EEI and organic growth reduced the impact of these unfavorable items
on
current year earnings.
Prior
to
the third quarter of 2006, Ameren reported one segment, Utility Operations,
comprising electric generation and electric and gas transmission and
distribution operations, with Other including Ameren holding company activity.
As a result of the following changes in circumstances, Ameren, UE, CILCORP
and
CILCO changed their segments in the third quarter of 2006:
· |
the
Ameren Companies’ chief operating decision-making group began to assess
the performance and allocate resources based on a new segment structure
and made related organizational and management reporting changes
in the
third quarter of 2006;
|
· |
electric
generation deregulation in Illinois, which is currently scheduled
to
become effective January 1, 2007;
|
· |
the
expiration of affiliate power supply agreements for CIPS and CILCO,
and
other supply agreements for IP on December 31,
2006;
|
· |
the
July 2006 termination of the JDA among UE, Genco and CIPS effective
December 31, 2006; and
|
· |
the
September 2006 completion of a state-wide auction to procure power
for
CIPS, CILCO and IP for 2007 and beyond, and Marketing Company's sale
in
that auction of power being acquired from Genco and
AERG.
|
Prior
period presentation has been adjusted for comparative purposes.
Ameren
determined in the third quarter of 2006 that it has three reportable segments:
Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE
determined that it has one reportable segment: Missouri Regulated. CILCORP
and
CILCO determined that they have two reportable segments: Illinois Regulated
and
Non-rate-regulated Generation. A discussion of changes in components of net
income between periods by business segment is provided below where material.
See
Note 12 - Segment Information to our financial statements under Part I, Item
1,
of this report for further discussion of Ameren’s, UE’s, CILCORP’s and CILCO’s
business segments.
59
Because
it is a holding company, Ameren’s net income and cash flows are primarily
generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The
following table presents the contribution by Ameren’s principal subsidiaries to
Ameren’s consolidated net income for the three months and nine months ended
September 30, 2006 and 2005:
Three
Months
|
Nine
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Net
income (loss):
|
||||||||||||
UE(a)(b)
|
$
|
165
|
$
|
163
|
$
|
305
|
$
|
349
|
||||
CIPS
|
28
|
30
|
41
|
44
|
||||||||
Genco(a)
|
19
|
32
|
27
|
94
|
||||||||
CILCORP(a)
|
13
|
5
|
22
|
16
|
||||||||
IP
|
42
|
53
|
61
|
89
|
||||||||
Other(c)
|
26
|
(3
|
)
|
30
|
(6
|
)
|
||||||
Ameren
net income
|
$
|
293
|
$
|
280
|
$
|
486
|
$
|
586
|
(a) |
Includes
earnings from market-based interchange power sales that provided
the
following contributions to net income for the three-month and nine-month
periods, respectively:
|
UE:
|
2006
- $9 million, $43 million
|
2005
- $7 million, $53 million
|
|
Genco:
|
2006
- $2 million, $13 million
|
2005
- $3 million, $31 million
|
|
CILCORP:
|
2006
- $2 million, $14 million
|
2005 - $2 million, $11 million |
(b) |
Includes
earnings from a non-rate-regulated 40% interest in
EEI.
|
(c) |
Includes
earnings from non-rate-regulated operations and a 40% interest
in EEI held
by Development Company, corporate general and administrative
expenses,
and
intercompany eliminations.
|
RESULTS
OF OPERATIONS
Margins
The
following table presents the favorable (unfavorable) variations in electric
and
gas margins, by registrant company, defined as electric revenues less fuel
and
purchased power costs, and gas revenues less gas purchased for resale, for
the
three months and nine months ended September 30, 2006, as compared with the
year-ago periods. We consider electric, interchange and gas margins useful
measures to analyze the change in profitability of our electric and gas
operations between periods. We have included the analysis below as a complement
to the financial information we provide in accordance with GAAP. However, these
margins may not be a presentation defined under GAAP and may not be comparable
to other companies’ presentations or more useful than the GAAP information we
provide elsewhere in this report.
Three
Months
|
Ameren(a)
|
|
UE
|
CIPS
|
Genco
|
CILCORP
|
CILCO
|
IP
|
|||||||||||||
Electric
revenue change:
|
|||||||||||||||||||||
Effect
of weather (estimate)
|
$
|
(30
|
)
|
$
|
(10
|
)
|
$
|
(5
|
)
|
$
|
-
|
$
|
(6
|
)
|
$
|
(6
|
)
|
$
|
(9
|
)
|
|
Storm-related
outages
|
(3
|
)
|
(2
|
)
|
(2
|
)
|
2
|
-
|
-
|
(1
|
)
|
||||||||||
Wholesale
contracts(b)
|
(18
|
)
|
-
|
-
|
(18
|
)
|
-
|
-
|
-
|
||||||||||||
Interchange
revenues(c)
|
69
|
(26
|
)
|
(9
|
)
|
(19
|
)
|
4
|
4
|
-
|
|||||||||||
Growth
and other (estimate)
|
17
|
(2
|
)
|
-
|
7
|
5
|
4
|
27
|
|||||||||||||
Total
|
$
|
35
|
$
|
(40
|
)
|
$
|
(16
|
)
|
$
|
(28
|
)
|
$
|
3
|
$
|
2
|
$
|
17
|
||||
Fuel
and purchased power change:
|
|||||||||||||||||||||
Fuel:
|
|||||||||||||||||||||
Generation
and other
|
$
|
29
|
$
|
14
|
$
|
-
|
$
|
9
|
$
|
8
|
$
|
7
|
$
|
-
|
|||||||
Sales
of emissions allowances
|
(2
|
)
|
-
|
-
|
(21
|
)
|
-
|
-
|
-
|
||||||||||||
Price
|
(8
|
)
|
(4
|
)
|
-
|
-
|
(4
|
)
|
(4
|
)
|
-
|
||||||||||
Purchased
power
|
(6
|
)
|
38
|
15
|
5
|
7
|
7
|
(26
|
)
|
||||||||||||
Storm-related
energy costs
|
(2
|
)
|
(1
|
)
|
-
|
(1
|
)
|
-
|
-
|
-
|
|||||||||||
Total
|
$
|
11
|
$
|
47
|
$
|
15
|
$
|
(8
|
)
|
$
|
11
|
$
|
10
|
$
|
(26
|
)
|
|||||
Net
change in electric margins
|
$
|
46
|
$
|
7
|
$
|
(1
|
)
|
$
|
(36
|
)
|
$
|
14
|
$
|
12
|
$
|
(9
|
)
|
||||
Net
change in gas margins
|
$
|
-
|
$
|
(1
|
)
|
$
|
2
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
||||||
Nine
Months
|
|||||||||||||||||||||
Electric
revenue change:
|
|||||||||||||||||||||
Effect
of weather (estimate)
|
$
|
(60
|
)
|
$
|
(24
|
)
|
$
|
(12
|
)
|
$
|
-
|
$
|
(9
|
)
|
$
|
(9
|
)
|
$
|
(15
|
)
|
|
Storm-related
outages
|
(9
|
)
|
(8
|
)
|
(2
|
)
|
2
|
-
|
-
|
(1
|
)
|
||||||||||
Noranda
|
46
|
46
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Illinois
service territory transfer
|
3
|
(38
|
)
|
41
|
34
|
-
|
-
|
-
|
|||||||||||||
Wholesale
contracts(b)
|
(54
|
)
|
-
|
-
|
(54
|
)
|
-
|
-
|
-
|
||||||||||||
Interchange
revenues(c)
|
171
|
(5
|
)
|
(24
|
)
|
(38
|
)
|
(3
|
)
|
(3
|
)
|
-
|
|||||||||
Growth
and other (estimate)
|
2
|
(15
|
)
|
24
|
23
|
12
|
12
|
43
|
|||||||||||||
Total
|
$
|
99
|
$
|
(44
|
)
|
$
|
27
|
$
|
(33
|
)
|
$
|
-
|
$
|
-
|
$
|
27
|
60
Nine
Months
|
Ameren(a)
|
|
UE
|
CIPS
|
Genco
|
CILCORP
|
CILCO
|
IP
|
|||||||||||||
Fuel
and purchased power change:
|
|||||||||||||||||||||
Fuel:
|
|||||||||||||||||||||
Generation
and other
|
$
|
22
|
$
|
13
|
$
|
-
|
$
|
12
|
$
|
8
|
$
|
8
|
$
|
-
|
|||||||
Sale
of emissions allowances
|
(2
|
)
|
-
|
-
|
(21
|
)
|
-
|
-
|
-
|
||||||||||||
Price
|
(55
|
)
|
(34
|
)
|
-
|
(14
|
)
|
(7
|
)
|
(7
|
)
|
-
|
|||||||||
Purchased
power
|
(114
|
)
|
7
|
(24
|
)
|
(63
|
)
|
21
|
21
|
(52
|
)
|
||||||||||
Storm-related
energy costs
|
1
|
2
|
-
|
(1
|
)
|
-
|
-
|
-
|
|||||||||||||
Total
|
$
|
(148
|
)
|
$
|
(12
|
)
|
$
|
(24
|
)
|
$
|
(87
|
)
|
$
|
22
|
$
|
22
|
$
|
(52
|
)
|
||
Net
change in electric margins
|
$
|
(49
|
)
|
$
|
(56
|
)
|
$
|
3
|
$
|
(120
|
)
|
$
|
22
|
$
|
22
|
$
|
(25
|
)
|
|||
Net
change in gas margins
|
$
|
(6
|
)
|
$
|
(9
|
)
|
$
|
4
|
$
|
-
|
$
|
(4
|
)
|
$
|
(5
|
)
|
$
|
5
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
(b) |
Represents
several wholesale contracts that expired in 2005 and were not
renewed.
|
(c) |
Excludes
the impact from storm-related
outages.
|
The
table
below presents the favorable (unfavorable) variations in electric and gas
margins and non-utility revenues by segment for Ameren for the three months
and
nine months ended September 30, 2006, compared with the same periods in 2005.
Three
Months
|
Missouri
Regulated
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
Other
|
Intersegment
Eliminations
|
Consolidated
|
||||||||||||
Electric
margin change
|
$
|
7
|
$
|
(10
|
)
|
$
|
54
|
$
|
-
|
$
|
(5
|
)
|
$
|
46
|
||||
Gas
margin change
|
(1
|
)
|
2
|
-
|
-
|
(1
|
)
|
-
|
||||||||||
Other
revenues (Non-utility)
|
1
|
1
|
(1
|
)
|
(3
|
)
|
2
|
-
|
||||||||||
Total
|
$
|
7
|
$
|
(7
|
)
|
$
|
53
|
$
|
(3
|
)
|
$
|
(4
|
)
|
$
|
46
|
|||
Nine
Months
|
||||||||||||||||||
Electric
margin change
|
$
|
(56
|
)
|
$
|
(20
|
)
|
$
|
40
|
$
|
-
|
$
|
(13
|
)
|
$
|
(49
|
)
|
||
Gas
margin change
|
(9
|
)
|
4
|
-
|
-
|
(1
|
)
|
(6
|
)
|
|||||||||
Other
revenues (Non-utility)
|
2
|
3
|
(5
|
)
|
(5
|
)
|
2
|
(3
|
)
|
|||||||||
Total
|
$
|
(63
|
)
|
$
|
(13
|
)
|
$
|
35
|
$
|
(5
|
)
|
$
|
(12
|
)
|
$
|
(58
|
)
|
Ameren
Ameren’s
electric margin increased by $46 million, or 4%, for the three months and
decreased $49 million, or 2%, for the nine months ended September 30, 2006,
compared with the same periods in 2005. The following items had a favorable
impact on electric margins for the third quarter and first nine months of 2006
as compared to the year-ago periods:
· |
an
increase in margins on interchange sales of $59 million, or 181%,
and $121
million, or 67%, over the prior three and nine-month periods primarily
because of the expiration of EEI’s affiliate cost-based power supply
contract on December 31, 2005;
|
· |
organic
growth and industrial customers switching back to Illinois tariff
rates
because of the expiration of power contracts with
suppliers;
|
· |
sales
to Noranda, which commenced on June 1, 2005, that increased electric
margin by approximately $20 million at UE for the first nine
months;
|
· |
lower
emissions allowance costs totaling $10 million for both the quarter
and
nine months ended September 30, 2006; and
|
· |
MISO
Day Two Energy Market costs which were $5 million lower for the three
months ended September 30, 2006, compared with the same period in
2005.
|
The
following items had an unfavorable impact on electric margins for the third
quarter and first nine months of 2006 as compared to the year-ago
periods:
· |
unfavorable
weather conditions as evidenced by a 10% decline in cooling degree-days
for both the three months and nine months ended September 30, 2006,
and a
9% decrease in heating degree-days for the nine months ended September
30,
2006, compared with the same period in
2005;
|
· |
severe
storm-related outages which negatively impacted electric sales and
resulted in an estimated net reduction in overall electric margin
of $5
million and $8 million in the third quarter and the nine months ended
September 30, 2006;
|
· |
wholesale
margins which were approximately $8 million lower for the nine months
ended September 30, 2006 due primarily to the expiration of several
large
contracts in 2005;
|
· |
incremental
fees of $4 million levied by FERC for the nine months ended September
30,
2006, upon completion of its cost study for generation benefits provided
to UE’s Osage hydroelectric plant;
|
· |
a
7% increase in the third quarter and 11% increase for the first nine
months of 2006 in coal and transportation prices;
|
61
· |
MISO
Day Two Energy Market costs which were $16 million higher for the
nine
months ended September 30, 2006, compared with the same periods in
2005 as
this market did not begin until the second quarter of 2005;
|
· |
reduced
margins because of the unavailability of UE’s Taum Sauk hydroelectric
plant totaling an estimated $10 million and $20 million in the third
quarter and first nine months of
2006;
|
· |
reduced
margins from UE’s other hydroelectric generation due to drought-like
conditions across the central and southern portions of Missouri totaling
approximately $5 million for the third quarter and $24 million for
the
nine months ended September 30, 2006, as compared to prior
periods;
|
· |
an
unscheduled outage in the second quarter of 2006 at UE’s Callaway nuclear
plant, which reduced electric margins by an estimated $20 million.
In the
third quarter of 2005, there was a scheduled refueling and maintenance
outage that reduced electric margins by $4 million. The lack of a
similar
outage in the third quarter of 2006 benefited current year electric
margins; and
|
· |
reduced
transmission service revenues primarily due to elimination of interim
cost
recovery mechanisms and reduced revenues associated with the MISO
Day Two
Energy Market.
|
Ameren’s
gas margins were flat for the three months and decreased by $6 million, or
2%,
for the nine months ended September 30, 2006, compared with the same periods
in
2005, respectively.
Ameren’s
decrease in gas margins for the nine months ended September 30, 2006, compared
with the same period in 2005, was primarily due to mild weather conditions
as
evidenced by a 9% decrease in heating degree-days. Weather-sensitive residential
and commercial gas sales volumes decreased 9% and 8%, respectively, for the
nine
months ended September 30, 2006, compared with the same period in 2005. The
decrease in gas margin was reduced by, among other things, the effect of an
IP
rate increase effective in May 2005 that added revenues of $6 million in the
first nine months of 2006.
Missouri
Regulated
UE
UE’s
electric margin increased by $7 million, or 1%, for three months and decreased
by $56 million, or 4%, for the nine months ended September 30, 2006, compared
to
the same periods in 2005. The increase in the electric margin for the three
months ended September 30, 2006, was primarily due to:
· |
the
lack of a scheduled Callaway nuclear plant refueling and maintenance
outage in 2006; and
|
· |
decreased
MISO Day Two Energy Market costs totaling $6
million.
|
Factors
that reduced the increase in electric margin for the three months and
contributed to the decrease in electric margins for the nine months ended
September 30, 2006, as compared to the same periods in the prior year were
as
follows:
· |
unfavorable
weather conditions as evidenced by a 6% decline in cooling degree-days
for
the three months and 8% decline for the nine months ended September
30,
2006;
|
· |
severe
spring and summer storms in 2006 caused outages which reduced electric
sales and resulted in an estimated net reduction in overall electric
margin of $3 million for the third quarter and $6 million for the
first
nine months of 2006;
|
· |
the
transfer of UE’s Illinois service territory on May 2, 2005, to CIPS, which
resulted in lost margins compared to the prior periods, totaling
an
estimated $22 million for the first nine months of 2006 with no impact
on
the third quarter of 2006;
|
· |
lower
margins on interchange sales as a result of lower power prices in
the
third quarter and first nine months of 2006. Average interchange
revenue
realization per kilowatthour was 50% and 9% lower for the third quarter
and first nine months of 2006, respectively. However, margins on
interchange sales benefited from the January 2006 amendment of the
JDA.
The MoPSC-required and FERC-approved
change in the JDA methodology to base the allocation of third-party
short-term power sales of excess generation on generation output
instead
of load requirements, effective January 10, 2006, resulted in $3
million
and $17 million in incremental margins on interchange sales for UE
for the
three months and nine months ended September 30, 2006,
respectively;
|
· |
a
4% and 11% increase in coal and related transportation prices for
the
third quarter and first nine months of 2006;
|
· |
fees
of $4 million levied by FERC for the nine months ended September
30, 2006,
for generation benefits provided to UE’s Osage hydroelectric
plant;
|
· |
reduced
margins because of the unavailability of UE’s Taum Sauk hydroelectric
plant;
|
· |
reduced
electric margins from UE’s other hydroelectric generation due to
drought-like conditions across the central and southern portions
of
Missouri;
|
· |
unscheduled
outage at UE’s Callaway nuclear plant in the second quarter of
2006;
|
· |
MISO
Day Two Energy Market costs, which were $8 million higher for the
first
nine months of 2006 as this market did not begin until the second
quarter
of 2005;
|
62
· |
the
expiration of a cost-based power supply contract with EEI on December
31,
2005; and
|
· |
reduced
transmission service revenues primarily due to elimination of interim
cost
recovery mechanisms and reduced revenues associated with the MISO
Day Two
Energy Market.
|
The
decrease in UE’s electric margins for the nine months ended September 30, 2006,
compared with the same period in 2005, was reduced by increased sales to Noranda
and the lack of a scheduled Callaway refueling and maintenance outage in
2006.
UE’s
gas
margin decreased by $1 million, or 9%, for the three months and $9 million,
or
17%, for the nine months ended September 30, 2006, compared with the same
periods in 2005. UE’s decrease in gas margins was due to mild winter weather
conditions, as evidenced by a 9% decrease in heating degree-days for the nine
months ended September 30, 2006. In addition, UE’s gas margin was negatively
impacted by the transfer of UE’s Illinois service territory to CIPS in May 2005,
which reduced gas margins by $3 million for the nine months ended September
30,
2006, compared with the same period in 2005.
Illinois
Regulated
Illinois
Regulated’s electric margin decreased by $10 million, or 3%, for the three
months and $20 million, or 3%, for the nine months ended September 30, 2006,
compared with the same periods in 2005.
Illinois
Regulated’s gas margin increased by $2 million, or 4%, for the three months and
$4 million, or 2%, for the nine months ended September 30, 2006.
CIPS
CIPS’
electric margin decreased by $1 million, or 1%, for the three months and
increased by $3 million, or 1%, for the nine months ended September 30, 2006,
compared to the same periods in 2005. The increase in electric margins for
the
first nine months of 2006 was primarily because of:
· |
the
transfer to CIPS of UE’s Illinois service territory on May 2, 2005, which
generated incremental electric margins of $4 million for the first
nine
months of 2006, and
|
· |
customers
switching back to CIPS from Marketing Company in 2006 because tariff
rates
were below market rates for power.
|
CIPS’
increase in electric margins was reduced by the following factors for the third
quarter and first nine months of 2006, compared to the same periods in 2005,
as
follows:
· |
increased
MISO Day Two Energy Market costs, totaling $2 million for the nine
months
ended September 30, 2006, compared with the same period in 2005 as
this
market did not begin until the second quarter of
2005;
|
· |
severe
summer storms caused outages that reduced electric sales and resulted
in
an estimated net reduction in electric margin of $2 million for the
three
months and nine months ended September 30, 2006;
|
· |
unfavorable
weather conditions as evidenced by a 12% and 8% decrease in cooling
degree-days for the third quarter and first nine months of 2006;
and
|
· |
reduced
transmission service revenues primarily due to elimination of interim
cost
recovery mechanisms and reduced revenues associated with the MISO
Day Two
Energy Market.
|
Due
to
the expiration of CIPS’ cost-based power supply agreement with EEI in December
2005, where CIPS sold its entitlements under the agreement to Marketing Company,
both interchange revenues and purchased power expenses decreased $9 million
and
$24 million for the three months and nine months ended September 30,
2006.
CIPS’
gas
margin increased by $2 million for the three months and $4 million, or 9%,
for
the nine months ended September 30, 2006, as compared with the same periods
in
2005 primarily because of the transfer to CIPS of UE’s Illinois service
territory in May 2005. The increase in gas margin was reduced by extremely
mild
winter weather as evidenced by an 11% decrease in heating degree-days for the
nine months ended September 30, 2006, as compared with the same period in
2005.
CILCO
(Illinois Regulated)
The
following table provides a reconciliation of CILCO’s change in electric margin
by segment to CILCO’s total change in electric margin for the three months and
nine months ended September 30, 2006, as compared with the same periods in
2005:
Three
Months
|
Nine
Months
|
|||||
CILCO
(Illinois Regulated)
|
$
|
(1
|
)
|
$
|
2
|
|
CILCO
(AERG)
|
13
|
20
|
||||
Total
change in electric margin
|
$
|
12
|
$
|
22
|
CILCO’s
Illinois Regulated electric margin decreased by $1 million, or 2%, for the
three
months ended September 30, 2006, as compared to the year-ago period, primarily
because of unfavorable weather conditions as evidenced by a 19% decrease in
cooling degree-days.
CILCO’s
Illinois Regulated electric margin increased by $2 million, or 2%, for the
nine
months ended September 30, 2006, compared to the same periods in 2005. The
increase in electric margins was primarily because of:
63
· |
increased
native load growth, primarily in the industrial sector,
and
|
· |
lower
MISO Day Two Energy Market costs.
|
The
increase in CILCO’s (Illinois Regulated) electric margins for the nine months
ended September 30, 2006, was reduced by the impact of unfavorable weather
conditions as evidenced by the decrease in cooling degree-days and a 6% decrease
in heating degree-days.
See
Non-rate-regulated Generation under Results of Operations for a detailed
explanation of CILCO’s (AERG) change in electric margin for the three months and
nine months ended September 30, 2006, as compared with the same periods in
2005.
CILCO’s
(Illinois Regulated) gas margin was flat for the three months and decreased
by
$5 million, or 8%, for the nine months ended September 30, 2006, compared to
the
same periods in 2005. This decrease was primarily as a result of the mild winter
weather conditions in CILCO’s service territory.
IP
IP’s
electric margin decreased by $9 million, or 5%, for the three months and $25
million, or 7%, for the nine months ended September 30, 2006, compared with
the
same periods in 2005 primarily because of:
· |
increased
purchased power costs as a result of the expiration of its cost-based
power supply agreement with EEI on December 31, 2005, and increased
purchased power prices;
|
· |
reduced
transmission service revenues primarily due to the elimination of
interim
cost recovery mechanisms and reduced revenues associated with the
MISO Day
Two Energy Market;
|
· |
unfavorable
weather conditions, including a 12% and 10% decrease in cooling
degree-days for the three months and nine months ended September
30, 2006,
compared with the same periods in 2006;
and
|
· |
severe
summer storms caused outages that reduced electric sales and resulted
in
an estimated net reduction in electric margin of $1 million for the
three
months and nine months ended September 30,
2006.
|
The
decrease in IP’s electric margins in the third quarter and first nine months of
2006 was reduced by an increase in revenues as a result of customers switching
back to IP because tariff rates were below market rates for power and lower
transmission expenses due, in part, to a $6 million favorable settlement of
disputed ancillary charges with MISO.
IP’s
gas
margin was flat for the three months and increased by $5 million, or 5%, for
the
nine months ended September 30, 2006, compared to the same periods in 2005.
The
increase in the nine months ended September 30, 2006, was primarily because
of a
rate increase effective in May 2005 that added revenues of $6 million in 2006.
This increase was reduced by the extremely mild winter weather conditions as
evidenced by a 10% decrease in heating degree-days in the first nine months
of
2006 as compared with the year-ago period in IP’s service
territory.
Non-rate-regulated
Generation
Non-rate-regulated
Generation’s electric margins increased by $54 million, or 32%, for the three
months and $40 million, or 7%, for the nine months ended September 30, 2006,
compared with the same periods in 2005.
Genco
Genco’s
electric margin decreased by $36 million, or 29%, and $120 million, or 32%,
for
the three months and nine months ended September 30, 2006, compared with the
same periods in 2005, primarily because of:
· |
lower
wholesale margins as Genco purchased additional power at higher costs
due,
in part, to the expiration of the coal-based power supply contract
between
EEI and its affiliates on December 31, 2005;
|
· |
higher
net emission allowance costs because of a $21 million gain at Genco
in the
third quarter of 2005 resulting from the nonmonetary swap of certain
earlier vintage year SO2
emission allowances for later vintage year
allowances;
|
· |
a
7% and 9% increase in coal and transportation prices for the three
months
and nine months ended September 30, 2006, compared with the same
periods
in 2005;
|
· |
reduced
plant availability of major coal-fired units in
2006;
|
· |
lower
margins on interchange sales for the three months and nine months
ended
September 30, 2006, compared with the same periods in 2005, primarily
because of lower power prices, and a $3 million and $17 million reduction
in 2006 due to the amendment of the JDA among UE, Genco and CIPS;
and
|
· |
higher
MISO Day Two Market costs totaling $5 million for the third quarter
and
$11 million for the first nine months of 2006 as this market did
not begin
until the second quarter of 2005.
|
Genco’s
decrease in electric margins was reduced by an increase in electric margins
due
to the May 2005 transfer of UE’s Illinois service territory to CIPS. Genco
supplies CIPS’ power requirements through a power supply agreement with
Marketing Company.
64
CILCO
(AERG)
For
the
three- and nine-month periods ended September 30, 2006, AERG’s electric margin
increased by $13 million, or 97%, for the three months and $20 million, or
29%,
for the nine months ended September 30, 2006, compared with the same periods
in
2005 primarily because of:
· |
lower
purchased power costs due to improved power plant
availability;
|
· |
decreases
in emission allowance utilization expenses of $3 million and $7 million
for the third quarter and first nine months of 2006, respectively;
and
|
· |
an
increase in margins on interchange sales of $5 million for the first
nine
months of 2006, due in part to improved plant
availability.
|
EEI
EEI’s
electric margins increased by $87 million for the three months and $179 million
for the nine months ended September 30, 2006, compared with the same periods
in
2005 primarily because of the increase in margins on interchange sales resulting
from the expiration of its affiliate cost-based sales contract on December
31,
2005, and its replacement with a market-based sales contract.
Operating
Expenses and Other Statement of Income Items
Other
Operations and Maintenance
Ameren
Three
months - Other operations and maintenance expenses were comparable between
periods. We experienced the most damaging storms in the company’s history in our
service territory this summer resulting in the loss of power to approximately
950,000 electric customers and expenses of $23 million. In addition, incremental
costs of $7 million as a result of the December 2005 Taum Sauk plant incident
increased 2006 third quarter other operations and maintenance expenses. Reducing
the impact of this unfavorable item was decreased bad debt expense and an
impairment of $10 million recorded in the prior-year period related to an
investment in an aircraft leveraged lease with Delta Air Lines, Inc. due to
its
Chapter 11 bankruptcy filing in September 2005. No such impairment occurred
in
the current year period.
Nine
months - Other operations and maintenance expenses increased $25 million
primarily because of storm expenditures in the current year as discussed above,
$17 million of costs related to the December 2005 reservoir breach at UE’s Taum
Sauk plant, and losses on sales of leveraged lease assets in the second quarter
of 2006 that increased other operations and maintenance expenses by $7 million.
Additionally, higher power plant maintenance expenses due to the timing of
maintenance outages and an increase in legal fees for environmental issues
and
general litigation resulted in increased other operations and maintenance
expenses. Reducing the impact of these items was a reduction in bad debt expense
and injuries and damages expense along with the impairment of the Delta Air
Lines, Inc. leveraged lease recorded in the prior year, which did not recur
in
the current year, as discussed above.
Variations
in other operations and maintenance expenses at Ameren’s, CILCORP’s and CILCO’s
business segments and for the Ameren Companies for the three months and nine
months ended September 30, 2006, compared with the same periods in 2005 were
as
follows:
Missouri
Regulated
UE
Three
months - Other operations and maintenance expenses increased $15 million
primarily because of repair expenditures related to severe storms in UE’s
service territory this summer of $16 million. Additionally, incremental costs
of
$7 million were recorded related to the December 2005 Taum Sauk plant incident
because of a settlement with FERC resolving all potential federal liability.
Reducing the impact of these unfavorable items were lower employee benefit
costs
and legal fees. Additionally, in the third quarter of 2005, we began a scheduled
refueling and maintenance outage at UE’s Callaway nuclear plant, resulting in
maintenance expenses of $3 million, which did not recur this year.
Nine
months - Other operations and maintenance expenses increased $8 million
primarily because of storm repair expenditures, as noted above, and incremental
costs associated with the Taum Sauk incident of $17 million. Reducing the impact
of these unfavorable items were decreased other operations and maintenance
expenses of $7 million resulting from the transfer of UE’s Illinois service
territory to CIPS in May 2005. Additionally, lower injuries and damages
expenses, due in part to the settlement of claims, decreased bad debt expense
and employee benefit costs, and the lack of a scheduled Callaway refueling
and
maintenance outage, as noted above, resulted in a reduction in other operations
and maintenance expenses.
Illinois
Regulated
Other
operations and maintenance expenses increased $3 million and $27 million in
Illinois Regulated primarily at IP for the three months and nine months ended
September 30, 2006, respectively, compared with the same periods in
2005.
65
CIPS
Three
months - Other operations and maintenance expenses were comparable between
periods as storm repair expenditures in the current period were offset by a
reduction in bad debt expense.
Nine
months - Other operations and maintenance expenses increased $8 million
primarily because of storm repair expenditures and the transfer of UE’s Illinois
service territory to CIPS in May 2005, which resulted in additional other
operations and maintenance expenses of $7 million. The negative effect of these
items was reduced by lower bad debt expense.
CILCO
(Illinois Regulated)
Three
months - Other operations and maintenance expenses were comparable between
periods.
Nine
months - Other operations and maintenance expenses decreased $3 million
primarily because of lower employee benefit costs, partially offset by increased
legal fees.
IP
Three
months - Other operations and maintenance expenses increased $4 million
primarily because of storm repair expenditures of $4 million in the current
period and increased injuries and damages expenses, partially offset by
decreased labor costs.
Nine
months - Other operations and maintenance expenses increased $22 million
primarily because of storm repair expenditures, along with higher rental
expenses and injuries and damages expenses. The negative effect of these items
was reduced by lower labor costs.
Non-rate-regulated
Generation
Other
operations and maintenance expenses were comparable at Non-rate-regulated
Generation in the third quarter of this year compared to the third quarter
of
the prior year. Other operations and maintenance expenses increased $11 million
for the nine months ended September 30, 2006, compared with the same period
in
2005, primarily at Genco.
Genco
Three
months - Other operations and maintenance expenses were comparable between
periods.
Nine
months - Other operations and maintenance expenses increased $5 million
primarily because of higher maintenance expenses resulting from increased power
plant maintenance outages in the current-year period.
CILCORP
(Parent Company Only), EEI & CILCO (AERG)
Three
months and nine months - Other operations and maintenance expenses were
comparable between periods.
Other
Three
months - In the third quarter of 2005, Ameren recorded an impairment of $10
million at a nonregistrant subsidiary related to an investment in an aircraft
leveraged lease to Delta Air Lines, Inc. due to its Chapter 11 bankruptcy filing
in September 2005. No such impairment occurred in the current year period.
Nine
months - In the second quarter of 2006, losses on sales of leveraged lease
assets were recorded at CILCO. The leveraged lease losses in other operations
and maintenance expenses were partially offset by a tax benefit reflected in
income taxes. The lack of the 2005 leveraged lease impairment associated with
Delta Air Lines, Inc. in the current year reduced the year-over-year impact
of
the leveraged lease losses for the first nine-months of 2006.
Depreciation
and Amortization
Ameren
Three
months - Depreciation and amortization expenses increased $4 million primarily
because of capital additions.
Nine
months - Depreciation and amortization expenses increased $17 million primarily
as a result of capital additions and the impairment of an intangible asset
associated with the CILCORP acquisition.
Variations
in depreciation and amortization expenses at Ameren’s business segments for the
three months and nine months ended September 30, 2006, compared with the same
periods in 2005 were as follows:
Missouri
Regulated
UE
Three
months - Depreciation and amortization expenses increased $3 million primarily
because of capital additions.
Nine
months - Depreciation and amortization expenses increased $12 million primarily
because of capital additions, a portion of which were related to new steam
generators and turbine rotors installed during the refueling and maintenance
outage at the Callaway nuclear plant in 2005. Additionally, depreciation
increased due to CTs transferred to UE from
66
Genco
in
May 2005. Reducing the impact of these increases was a reduction of depreciation
due to the transfer of property to CIPS as part of the Illinois service
territory transfer in May 2005.
Illinois
Regulated
Depreciation
and amortization expenses were comparable at Illinois Regulated for the three
months and nine months ended September 30, 2006, compared with the same periods
in 2005.
CIPS
Three
months - Depreciation and amortization expenses were comparable between
periods.
Nine
months - Depreciation and amortization expenses increased $2 million primarily
because of capital additions and depreciation on property transferred to CIPS
from UE in the May 2005 Illinois service territory transfer.
CILCO
(Illinois Regulated) & IP
Three
months and nine months - Depreciation and amortization expenses were comparable
between periods.
Non-rate-regulated
Generation
Depreciation
and amortization expenses were comparable at Non-rate-regulated Generation
in
the third quarter of 2006 compared to the third quarter of last year.
Depreciation and amortization expenses increased $3 million for the nine months
ended September 30, 2006, compared with the same period in 2005.
Genco,
EEI & CILCO (AERG)
Three
months and nine months - Depreciation and amortization expenses were comparable
between periods.
CILCORP
(Parent Company Only)
Three
months - Depreciation and amortization expenses were comparable between
periods.
Nine
months - Depreciation and amortization expenses increased $4 million primarily
because of the recording of an impairment of an intangible asset established
in
conjunction with Ameren’s acquisition of CILCORP.
Taxes
Other Than Income Taxes
Ameren
Three
months - Taxes other than income taxes were comparable between
periods.
Nine
months - Taxes other than income taxes increased $18 million primarily as a
result of higher gross receipts and excise taxes and higher property taxes.
Variations
in taxes other than income taxes at Ameren’s business segments for the three
months and nine months ended September 30, 2006, compared with the same periods
in 2005 were as follows:
Missouri
Regulated
UE
Three
months - Taxes other than income taxes were comparable between
periods.
Nine
months - Taxes other than income taxes increased $4 million primarily as a
result of higher gross receipts taxes.
Illinois
Regulated
Taxes
other than income taxes were comparable at Illinois Regulated in the third
quarter of this year compared to the third quarter of the prior year. Taxes
other than income taxes increased $8 million for the nine months ended September
30, 2006, compared with the same period in 2005.
CIPS
Three
months - Taxes other than income taxes were comparable between
periods.
Nine
months - Taxes other than income taxes increased $6 million primarily as a
result of higher excise taxes.
CILCO
(Illinois Regulated)
Three
months - Taxes other than income taxes were comparable between
periods.
Nine
months - Taxes other than income taxes increased $3 million primarily as a
result of higher excise taxes.
IP
Three
months and nine months - Taxes other than income taxes were comparable between
periods.
67
Non-rate-regulated
Generation
Taxes
other than income taxes were comparable at Non-rate-regulated Generation in
the
third quarter of 2006 compared to the third quarter of the prior year. Taxes
other than income taxes increased $8 million for the nine months ended September
30, 2006, compared with the same period in 2005, primarily at
Genco.
Genco
Three
months - Taxes other than income taxes were comparable between
periods.
Nine
months - Taxes other than income taxes increased $7 million primarily because
of
higher property taxes due to a favorable court decision in the first quarter
of
2005 that did not recur in 2006.
CILCORP
(Parent Company Only), EEI & CILCO (AERG)
Three
months and nine months - Taxes other than income taxes were comparable between
periods.
Other
Income and Expenses
Ameren
Three
months and nine months - Miscellaneous income decreased $1 million and $6
million primarily as a result of lower capitalization of equity funds used
during construction in the current year periods. Miscellaneous expense increased
$2 million in the third quarter primarily because of activity related to
investments in low income housing credits. Miscellaneous expense decreased
$3
million in the nine months primarily due to the write-off of unrecoverable
natural gas costs in the prior year as noted below.
Variations
in other income and expenses at Ameren’s, CILCORP’s and CILCO’s business
segments for the three months and nine months ended September 30, 2006, compared
with the same periods in 2005 were as follows:
Missouri
Regulated
UE
Three
months - Other income and expenses were comparable between periods.
Nine
months - Miscellaneous income decreased $6 million primarily as a result of
lower capitalization of equity funds used during construction in 2006. In the
prior-year period, UE replaced steam generators and turbine rotors at the
Callaway nuclear plant. Miscellaneous expense was comparable between
periods.
Illinois
Regulated
Other
income and expenses were comparable at Illinois Regulated in the third quarter
of 2006 compared to the third quarter of the prior year. Other income and
expenses were favorable $3 million for the nine months ended September 30,
2006,
compared with the same period in 2005.
CIPS
Three
months - Miscellaneous income and miscellaneous expense were comparable between
periods.
Nine
months - Miscellaneous income was comparable between periods. Miscellaneous
expense decreased $4 million primarily as a result of the write-off in 2005
of
unrecoverable natural gas costs.
CILCO
(Illinois Regulated)
Three
months - Miscellaneous income and miscellaneous expense were comparable between
periods.
Nine
months - Miscellaneous income was comparable between periods. Miscellaneous
expense decreased $3 million primarily as a result of the write-off in the
prior
year of unrecoverable natural gas costs.
IP
Three
months - Miscellaneous income and miscellaneous expense were comparable between
periods.
Nine
months - Miscellaneous income decreased $2 million primarily because of lower
capitalization of equity funds used during construction. Miscellaneous expenses
increased $2 million primarily as a result of IP-related integration
costs.
Non-rate-regulated
Generation
Other
income and expenses were comparable at Non-rate-regulated Generation for the
three months and nine months ended September 30, 2006, compared with the same
periods in 2005.
Genco,
CILCORP (Parent Company Only), EEI & CILCO (AERG)
Three
months and nine months - Other income and expenses were comparable between
periods.
68
Interest
Ameren
Three
months and nine months - Interest expense increased $12 million and $17 million
primarily because of items noted below.
Variations
in interest expense at Ameren’s, CILCORP’s and CILCO’s business segments for the
three months and nine months ended September 30, 2006, compared with the same
periods in 2005 were as follows:
Missouri
Regulated
UE
Three
months and nine months - Interest expense increased $6 million and $26 million,
respectively, primarily because of the issuances of $300 million of senior
secured notes in July 2005 and $260 million of senior secured notes in December
2005 along with increased short-term borrowings, partially resulting from the
purchase of CTs in the first quarter of 2006.
Illinois
Regulated
Interest
expense was comparable at Illinois Regulated in the third quarter of this year
compared to the third quarter of the prior year. Interest expense increased
$6
million for the nine months ended September 30, 2006, compared with the same
period in 2005, principally at IP.
CIPS
& CILCO (Illinois Regulated)
Three
months and nine months - Interest expense was comparable between
periods.
IP
Three
months - Interest expense was comparable between periods.
Nine
months - Interest expense increased $5 million primarily because of the issuance
of $75 million of senior secured notes in June 2006 along with increased money
pool borrowings.
Non-rate-regulated
Generation
Interest
expense was comparable at Non-rate-regulated Generation in the third quarter
of
2006 compared to the third quarter of the prior year. Interest expense decreased
$14 million for the nine months ended September 30, 2006, compared with the
same
period in 2005, principally at Genco.
Genco
Three
months - Interest expense was comparable as a reduction in interest expense
of
$4 million resulting from the maturity of $225 million of senior notes in
November 2005 was offset by increased money pool borrowings.
Nine
months - Interest expense decreased $12 million primarily because of the
maturity of the $225 million senior notes.
CILCORP
(Parent Company Only)
Three
months - Interest expense was comparable between periods.
Nine
months - Interest expense was comparable as a decrease of $3 million due to
the
repurchase of $85 million of 8.70% senior notes in 2005 was offset by increased
money pool borrowings.
EEI
&
CILCO (AERG)
Three
months and nine months - Interest expense was comparable between
periods.
Income
Taxes
Ameren
Three
months and nine months - Effective tax rate increased in the third quarter
of
the current year primarily because of items discussed below. Effective tax
rate
for the nine months was comparable to the prior-year period.
Variations
in effective tax rates at Ameren’s, CILCORP’s and CILCO’s business segments for
the three months and nine months ended September 30, 2006, compared with the
same periods in 2005 were as follows:
Missouri
Regulated
UE
Three
months and nine months - Effective tax rate increased over the prior year
primarily because of non-deductible items for tax purposes and an increase
in
reserves for uncertain tax positions.
Illinois
Regulated
Effective
tax rate increased at Illinois Regulated for the three months and nine months
ended September 30, 2006, compared with the same periods in 2005.
69
CIPS
Three
months - Effective tax rate increased primarily because of the settlement of
uncertain tax positions in the current year.
Nine
months - Effective tax rates were comparable between periods.
CILCO
(Illinois Regulated)
Three
months and nine months - Effective tax rate increased primarily because of
a
reduction in a permanent deduction allowed for tax purposes that was not allowed
for book purposes.
IP
Three
months and nine months - Effective tax rates were comparable between periods.
Non-rate-regulated
Generation
Effective
tax rate decreased at Non-rate-regulated Generation for the three months and
nine months ended September 30, 2006, compared with the same periods in
2005.
Genco
Three
months and nine months - Effective tax rate decreased primarily because of
the
settlement of uncertain tax positions in the current year.
CILCORP
(Parent Company Only)
Three
months and nine months - Effective tax rates were comparable between
periods.
CILCO
(AERG)
Three
months and nine months - Effective tax rate decreased primarily because of
the
settlement of uncertain tax positions in the current year.
EEI
Three
months and nine months - Effective tax rates were comparable between periods.
LIQUIDITY
AND CAPITAL RESOURCES
The
tariff-based gross margins of Ameren’s rate-regulated utility operating
companies (UE, CIPS, CILCO and IP) continue to be the principal source of cash
from operating activities for Ameren and its rate-regulated subsidiaries. A
diversified retail-customer mix of primarily rate-regulated residential,
commercial and industrial classes and a commodity mix of gas and electric
service provide a reasonably predictable source of cash flows for Ameren, UE,
CIPS, CILCO and IP. For operating cash flows, Genco principally relies on power
sales to an affiliate under a contract expiring at the end of 2006 and sales
to
other wholesale and industrial customers under short and long-term contracts.
Commencing in 2007, Genco and AERG expect to sell power previously sold under
contracts expiring at the end of 2006 to Marketing Company, which has sold
power
through the Illinois power procurement auction and is selling power through
other contracts with wholesale and retail customers. The amount of power that
Genco, AERG, EEI, Marketing Company and their affiliates may supply to CIPS,
CILCO and IP through the Illinois power procurement auction is limited to 35%
of
CIPS’, CILCO’s and IP’s annual load. In addition, each of the Ameren Companies
plans to use available cash, commercial paper and credit facilities to support
normal operations and other temporary capital requirements. The use of operating
cash flows and short-term borrowings to fund capital expenditures and other
investments may periodically result in a working capital deficit, as was the
case at September 30, 2006, for Ameren, UE, Genco, CILCORP, CILCO and IP. The
Ameren Companies will reduce their short-term borrowings with cash from
operations or discretionarily with long-term borrowings. See Note 2 - Rate
and
Regulatory Matters to our financial statements under Part I, Item 1 of this
report for a discussion of an Illinois legislative proposal to freeze electric
rates for CIPS, CILCO and IP. If such legislation is enacted, CIPS, CILCORP,
CILCO and IP will not have enough operating cash flow to support normal
operations.
70
The
following table presents net cash
provided by (used in) operating, investing and financing activities for the
nine
months ended September 30, 2006 and 2005:
Net
Cash Provided By
Operating
Activities
|
Net
Cash Provided By
(Used
In) Investing Activities
|
Net
Cash Provided By
(Used
In) Financing Activities
|
|||||||||||||||||||||||||
2006
|
2005
|
Variance
|
2006
|
2005
|
Variance
|
2006
|
2005
|
Variance
|
|||||||||||||||||||
Ameren(a)
|
$
|
1,030
|
$
|
1,177
|
$
|
(147
|
)
|
$
|
(1,005
|
)
|
$
|
(736
|
)
|
$
|
(269
|
)
|
$
|
(87
|
)
|
$
|
(232
|
)
|
$
|
145
|
|||
UE
|
593
|
712
|
(119
|
)
|
(584
|
)
|
(633
|
)
|
49
|
(27
|
)
|
(126
|
)
|
99
|
|||||||||||||
CIPS
|
127
|
148
|
(21
|
)
|
(47
|
)
|
(40
|
)
|
(7
|
)
|
(80
|
)
|
(110
|
)
|
30
|
||||||||||||
Genco
|
46
|
205
|
(159
|
)
|
(80
|
)
|
54
|
(134
|
)
|
36
|
(260
|
)
|
296
|
||||||||||||||
CILCORP
|
99
|
77
|
22
|
(28
|
)
|
(87
|
)
|
59
|
(71
|
)
|
7
|
(78
|
)
|
||||||||||||||
CILCO
|
122
|
101
|
21
|
(70
|
)
|
(91
|
)
|
21
|
(52
|
)
|
(10
|
)
|
(42
|
)
|
|||||||||||||
IP
|
106
|
207
|
(101
|
)
|
(127
|
)
|
(4
|
)
|
(123
|
)
|
21
|
(203
|
)
|
224
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
Cash
Flows from Operating Activities
Ameren’s
cash from operations decreased in the first nine months of 2006, as compared
with the first nine months of 2005, due primarily to decreases in electric
and
gas margins, and higher other operations and maintenance expenses as discussed
in Results of Operations, and a $133 million increase in income tax payments.
In
addition, there was an increase in cash used during the first nine months of
2006 for payment of 2005 costs, including real estate and property taxes, and
annual incentive compensation that was more than it was a year ago because
of
increased 2005 earnings relative to performance targets. The cash benefit from
reduced natural gas inventories that resulted in the first quarter of 2006
due
to the end of the winter heating season was offset in the second and third
quarters as a result of increased volume and per unit prices of coal inventory
purchases because of the coal supply issues experienced in the 2005 period
and
higher prices for coal in the 2006 period. Reducing these negative impacts
was
the collection of higher-than-normal trade receivables caused by cold December
2005 weather during the winter heating season. The cash impact from trade
receivables was more significant in the current period due to higher gas prices
and colder December weather in 2005 as compared with the year-ago
period.
At
UE,
cash from operating activities decreased in 2006 due to lower electric and
gas
margins and storm costs as discussed in Results of Operations, and cash used
for
working capital changes that primarily included increased payments of 2005
costs
in the first nine months of 2006 as compared with the year-ago period as
discussed above for Ameren. Also contributing to the decrease were operations
and maintenance expenditures of $14 million related to severe spring and summer
storms, increased income tax payments of $27 million compared to the year-ago
period, increased interest payments of $37 million, and $26 million paid (net
of
insurance recoveries to date) as a result of the breach at the Taum Sauk
hydroelectric facility. See Note 8 - Commitments and Contingencies -
Pumped-storage Hydroelectric Facility Breach for more information.
At
CIPS,
the negative cash effect of higher other operations and maintenance expenses
and
taxes other than income was partially offset by higher electric and gas margins,
as discussed in Results of Operations. Income tax payments increased $45 million
compared to the year-ago period. Partially offsetting this use of cash was
an
increase in collections of trade receivables as a result of colder December
2005
weather and higher gas prices compared to the year-ago period.
Genco’s
cash from operating activities in the first nine months of 2006 decreased
compared to the 2005 period primarily because of lower operating margins as
discussed in Results of Operations. Income tax payments decreased in 2006 by
$35
million compared to 2005, and interest payments were lower in the 2006 period
due to decreased debt outstanding.
Cash
from
operating activities increased for CILCORP and CILCO in the nine months ended
September 30, 2006, compared with the same period of 2005 primarily because
of
higher electric margins as discussed in Results of Operations, and an increase
in collections of trade receivables as a result of colder December 2005 weather
and higher gas prices compared to the year ago periods. In addition,
income tax payments decreased $15 million for CILCO and $25 million for CILCORP.
Partially offsetting these positive effects on cash were higher other operations
and maintenance expenses as discussed in Results of Operations.
IP’s
cash
from operations decreased in the nine months ended September 30, 2006, compared
with the 2005 period due to lower electric margins and higher other operations
and maintenance expenses as discussed above in Results of Operations. Also
contributing to IP’s decreased operating cash flows in 2006 were net income tax
refunds of $19 million in the 2006 period as compared with $32 million in the
year-ago period, and cash used during the first nine months of 2006 for payment
of 2005 costs including real estate and property taxes, and annual incentive
compensation that was
71
more
than
it was a year ago due to increased 2005 earnings relative to performance
targets.
Cash
Flows from Investing Activities
Ameren’s
increase in cash used in investing activities was primarily because of UE’s 2006
purchases of a 640-megawatt CT facility from affiliates of NRG Energy, Inc.,
and
510-megawatt and 340-megawatt CT facilities from subsidiaries of Aquila, Inc.
for a total of $292 million. The CT purchases are intended to meet UE’s
increased generating capacity needs and provide UE with additional flexibility
in determining future base-load generating capacity additions.
Excluding
CT purchases, Ameren’s capital expenditures were comparable in the first nine
months of 2006 as compared with the year-ago period. Emission allowance
purchases decreased $54 million in the first nine months of 2006 compared to
the
first nine months of 2005, while emission allowance sales increased $8 million.
The sale of leveraged lease investments provided an $11 million benefit to
Ameren’s cash from investing activities as discussed below.
UE’s
cash
used in investing activities decreased in the first nine months of 2006,
compared to the same period in 2005, principally because of $67 million received
from CIPS on an intercompany note. The cash effect of the $292 million in CT
purchases discussed above was more than the prior year effect of the $241
million purchase of two CTs from Genco and the purchase of CT equipment from
Development Company for $25 million. Excluding these transactions, UE’s capital
expenditures decreased $38 million, despite $22 million expended as a result
of
the severe spring and summer storms.
CIPS’
cash used in investing activities increased for the nine months ended September
30, 2006, compared with the 2005 period. Capital expenditures increased $22
million. Also negatively impacting CIPS’ investing cash flow was an $18 million
reduction in proceeds from CIPS’ note receivable from Genco in the 2006 period
as compared with the 2005 period. The decrease in proceeds from Genco resulted
from the May 1, 2005, amendment and restatement of the note. Reducing these
negative effects was a $33 million reduction of advances to the money pool
in
2006 as compared with 2005. The increased capital expenditures resulted partly
from CIPS’ expansion of its service territory because of its acquisition of UE’s
Illinois utility operations in May 2005. In addition, $6 million was expended
as
a result of severe summer storms. CIPS’ remaining capital expenditures were for
projects to improve the reliability of its electric and gas transmission and
distribution systems.
Genco
had
a net use of cash in investing activities for the first nine months of 2006
compared to a net source of cash during the same period in 2005. This was due
primarily to the 2005 sale of two CTs to UE in 2005 for $241 million. Purchases
of emission allowances were $45 million less in the first nine months of 2006
compared to the first nine months of 2005,
and
changes in net money pool advances resulted in a $65 million increase in cash
in
the 2006 period as compared to the 2005 period.
CILCORP’s
and CILCO’s cash used in investing activities decreased in the nine months ended
September 30, 2006, compared with the same period in 2005. CILCORP’s cash from
investing activities benefited from the repayment of Resources Company’s note
payable of $42 million that originated from the 2005 transfer of leveraged
leases from CILCORP to Resources Company. In addition, a subsidiary of CILCORP
and CILCO generated cash from investing activities of $11 million in the nine
months ended September 30, 2006, from the sale of its remaining leveraged lease
investments. Emission allowance purchases were $9 million less in the first
nine
months of 2006 compared to the first nine months of 2005.
IP’s
cash
used in investing activities increased in the first nine months of 2006 compared
to the same period in 2005, primarily because of the absence in the 2006 period
of proceeds received in the first nine months of 2005 from repayments received
for advances made to the money pool in prior periods. In addition, capital
expenditures increased $31 million over the year-ago period, which includes
$12
million as a result of severe summer storms, and increased expenditures to
maintain the reliability of IP’s electric and gas transmission and distribution
systems.
See
Note
8 - Commitments and Contingencies to our financial statements under Part I,
Item
1, of this report for a further discussion of future environmental capital
investment estimates.
We
continually review our generation portfolio and expected power needs. As a
result, we could modify our plans for generation capacity, which could include
changing the times when certain assets will be added to or removed from our
portfolio, the type of generation asset technology that will be employed, and
whether capacity may be purchased, among other things. Any changes that we
may
plan to make for future generating needs could result in significant capital
expenditures or losses being incurred, which could be material.
Cash
Flows from Financing Activities
Cash
used
in financing activities decreased for Ameren in the first nine months of 2006
from the year-ago period. Positive effects on cash included a net increase
of
$118 million in net short-term debt proceeds in the 2006 period, compared to
net
repayments of $394 million of short-term debt in the 2005 period, less long-term
debt redemptions,
72
repurchases
and maturities of $124 million, and borrowings on its $500 million credit
facility of $40 million in 2006. Negative effects on cash included a $150
million reduction in long-term debt proceeds compared to the year-ago period,
and a $352 million reduction in proceeds from the issuance of common stock.
The
reduction in common stock proceeds was due to the issuance of 7.4 million shares
in the 2005 period related to the settlement of a stock purchase obligation
in
Ameren’s adjustable conversion-rate equity security units.
UE’s
cash
used in financing activities decreased for the first nine months of 2006,
compared to the same period last year. Net changes in short-term debt resulted
in a $128 million positive effect on cash in 2006, but a $375 million negative
effect on cash in 2005. In addition, dividend payments decreased $55 million
in
the 2006 period compared to 2005. Partially offsetting these positive effects
on
cash were a $382 million reduction in long-term debt issuances, and a $79
million decrease in money pool borrowings. Net cash from financing activities
was principally used to fund the CT acquisitions.
CIPS’
cash used in financing activities decreased for the nine months ended September
30, 2006,
as
compared with the 2005 period. Cash was positively affected by a $66 million
decrease in money pool repayments in the 2006 period. A $29 million increase
in
dividends to Ameren negatively impacted CIPS’ cash from financing activities in
2006 as compared to the year-ago period. CIPS’ second quarter 2006 issuance of
$61 million of long-term debt was principally used to repay CIPS’ outstanding
balance on the intercompany note payable to UE that was originally issued with
the transfer of UE’s Illinois service territory to CIPS in 2005.
Genco
had
net cash proceeds from financing activities for the first nine months of 2006,
compared to a net use of cash for the same period last year. This is primarily
because in 2005, Genco used the $241 million from the CT sale to UE to make
principal payments on intercompany notes with CIPS and Ameren, and to reduce
its
money pool borrowings, and then make advances to the money pool. In addition,
$150 million of capital contributions received in 2006 from Ameren benefited
Genco’s financing cash flows. These capital contributions were made to reduce
Genco’s short-term debt. Reducing these positive effects on cash was a $34
million increase in dividend payments in the 2006 period as compared with the
2005 period.
CILCORP’s
and CILCO’s cash from financing activities benefited from CILCO’s long-term debt
issuances that generated $96 million in the 2006 period, as compared with no
long-term debt issuances in the 2005 period. The proceeds of this debt were
used
to redeem $20 million of long-term debt and to reduce money pool borrowings.
In
addition, CILCO’s subsidiary AERG borrowed $40 million in 2006 under the $500
million credit facility. These benefits in the 2006 period were partially offset
by the absence in 2006 of a $101 million capital contribution received in the
2005 period from Ameren, which was made to reduce CILCO’s short-term debt. In
addition, in 2006, CILCORP used cash of $32 million for redemptions, repurchases
and maturities of long-term debt as compared with $6 million in the 2005 period.
CILCORP’s net repayments of $30 million on its note payable to Ameren reduced
its financing cash flow by $58 million as compared with the year-ago period
because the 2005 period included net borrowings on this note that provided
CILCORP with cash.
Also
contributing to CILCORP’s and CILCO’s increase in cash used in financing
activities for the nine months ended September 30, 2006, as compared with the
year-ago period, were increased common stock dividends of $20 million and $45
million at CILCORP and CILCO, respectively, in the 2006 period as compared
with
the 2005 period.
IP
had a
net source of cash from financing activities in the first nine months of 2006,
compared to a net use of cash in the same period of the prior year. This was
primarily because of lower redemptions and repurchases of long-term debt of
$66
million. More debt was repaid in 2005 to improve IP’s credit profile. Another
positive effect on cash from financing activities was the absence in the 2006
period of $60 million of common stock dividend payments made in the 2005 period.
IP issued $75 million of long-term debt in 2006 as compared with no long-term
debt proceeds in the year-ago period. The proceeds were used to reduce money
pool borrowings.
Short-term
Borrowings and Liquidity
For
additional information on credit facilities, short-term borrowing activity,
relevant interest rates, and borrowings under Ameren’s utility and
non-state-regulated subsidiary money pool arrangements, see Note 3 - Credit
Facilities and Liquidity to our financial statements under Part I, Item 1,
of
this report.
73
The
following table presents the committed bank credit facilities of the Ameren
Companies and AERG as of October 31, 2006:
Credit
Facility
|
Expiration
|
Amount
Committed
|
Amount
Available
|
||||||
Ameren:(a)
|
|||||||||
Multiyear
revolving(b)(c)
|
July
2010
|
$
|
1,150
|
$
|
995
|
||||
CIPS,
CILCORP, CILCO, IP and AERG:
|
|||||||||
Multiyear
revolving(d)
|
January
2010
|
500
|
215
|
(a) |
Ameren’s
$350 million revolving credit facility was terminated on July 14,
2006.
See further discussion in Note 3 - Credit Facilities and Liquidity
to our
financial statements under Part I, Item 1, of this
report.
|
(b) |
Ameren
Companies may access this credit facility through intercompany borrowing
arrangements.
|
(c) |
UE
and Genco are authorized to be direct borrowers under this facility.
CIPS,
CILCO and IP were also authorized to be direct borrowers under this
agreement until July 13, 2006. See Note 3 - Credit Facilities and
Liquidity to our financial statements under Part I, Item 1, of this
report
for discussion of the amendment of this
facility.
|
(d) |
This
credit facility was entered into on July 14, 2006. The maximum amount
available to each borrower, including for issuance of letters of credit,
is limited as follows: CIPS -
$135
million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million
and AERG - $200 million. Effective September 8, 2006, CIPS, CILCO,
and IP
became authorized to borrow and obtain letters of credit for their
benefit
under this facility. See Note 3 - Credit Facilities and Liquidity
to our
financial statements under Part I, Item 1, of this report for discussion
of this credit facility.
|
In
addition to committed credit facilities, a further source of liquidity for
Ameren from time to time is available cash and cash equivalents. At September
30, 2006, Ameren had
$34
million of cash and cash equivalents.
With
the
repeal of PUHCA 1935 in February 2006, the issuance of short-term debt
securities by Ameren’s utility subsidiaries is now subject to approval by FERC
under the Federal Power Act. In March 2006, FERC issued an order authorizing
these subsidiaries to issue short-term debt securities subject to the following
limits on outstanding balances: UE -
$1
billion; CIPS - $250 million; and CILCO - $250 million. This authorization
was
effective as of April 1, 2006, and terminates on March 31, 2008.
Genco
is
also authorized by FERC in its March 2006 order to have up to $300 million
of
short-term debt outstanding at any time. IP, AERG and EEI have unlimited
short-term debt authorization from FERC.
With
the
repeal of PUHCA 1935, the issuance of short-term debt securities by Ameren
and
CILCORP, which was previously subject to SEC approval under PUHCA 1935, is
no
longer subject to approval by any regulatory body.
Long-term
Debt and Equity
The
following table presents the issuances of common stock and the issuances,
redemptions, repurchases and maturities of long-term debt and preferred stock
(net of any issuance discounts and including any redemption premiums) for the
nine months ended September 30, 2006 and 2005, for the Ameren Companies. For
additional information, see Note 4 - Long-term Debt and Equity Financings to
our
financial statements under Part I, Item 1, of this report.
Month
Issued, Redeemed,
|
Nine
Months
|
||||||||
Repurchased
or Matured
|
2006
|
2005
|
|||||||
Issuances
|
|||||||||
Long-term
debt
|
|||||||||
UE:(a)
|
|||||||||
5.00%
Senior secured notes due 2020
|
January
|
$
|
-
|
$
|
85
|
||||
5.30%
Senior secured notes due 2037
|
July
|
-
|
297
|
||||||
CIPS:(b)
|
|||||||||
6.70%
Senior secured notes due 2036
|
June
|
61
|
-
|
||||||
CILCO:(b)
|
|||||||||
Borrowings
from credit facility(c)
|
September
|
40
|
-
|
||||||
6.20%
Senior secured notes due 2016
|
June
|
54
|
-
|
||||||
6.70%
Senior secured notes due 2036
|
June
|
42
|
-
|
||||||
IP:(b)
|
|||||||||
6.25%
Senior secured notes due 2016
|
June
|
75
|
-
|
||||||
Total
Ameren long-term debt issuances
|
$
|
272
|
$
|
382
|
74
Month
Issued, Redeemed,
|
Nine
Months
|
||||||||
|
Repurchased
or Matured
|
2006
|
2005
|
||||||
Common
stock
|
|||||||||
Ameren:
|
|||||||||
7,402,320
Shares at $46.61(d)
|
May
|
$
|
-
|
$
|
345
|
||||
DRPlus
and 401(k)(e)
|
Various
|
78
|
85
|
||||||
Total
common stock issuances
|
$
|
78
|
$
|
430
|
|||||
Total
Ameren long-term debt and common stock issuances
|
$
|
350
|
$
|
812
|
|||||
Redemptions,
Repurchases and Maturities
|
|||||||||
Long-term
debt and preferred stock
|
|||||||||
Ameren:
|
|||||||||
Senior
notes due 2007(f)
|
February
|
$
|
-
|
$
|
95
|
||||
CIPS:
|
|||||||||
7.05%
First mortgage bonds due 2006
|
June
|
20
|
-
|
||||||
6.49%
First mortgage bonds due 2005
|
June
|
-
|
20
|
||||||
CILCORP:
|
|||||||||
9.375%
Senior notes due 2029
|
March/April
|
12
|
-
|
||||||
8.70%
Senior notes due 2009
|
May
|
-
|
6
|
||||||
CILCO:
|
|||||||||
7.73%
First mortgage bonds due 2025
|
July
|
20
|
-
|
||||||
5.85%
Series preferred stock
|
July
|
1
|
1
|
||||||
IP:
|
|||||||||
6.75%
Mortgage bonds due 2005
|
March
|
-
|
70
|
||||||
Notes
payable to IP SPT
|
|||||||||
5.54%
Series due 2007
|
Various
|
86
|
-
|
||||||
5.38%
Series due 2005
|
Various
|
-
|
71
|
||||||
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities | $ | 139 | 263 |
(a) |
Ameren’s
and UE’s long-term debt increased $240 million as a result of the first
quarter 2006 leasing transaction related to UE’s purchase of a
640-megawatt CT facility located in Audrain County, Missouri. No
capital
was raised as a result of UE’s assumption of the lease
obligations.
|
(b) |
On
September 8, 2006, CIPS, CILCO and IP issued mortgage bonds in the
amounts
of $135 million, $150 million and $150 million, respectively to secure
their obligations under the $500 million credit facility. See Note
3 -
Credit Facilities and Liquidity to our financial statements under
Part I,
Item 1, of this report.
|
(c) |
Represents
borrowings made by AERG under the $500 million credit facility discussed
in Note 3 - Credit Facilities and Liquidity to our financial statements
under Part I, Item 1, of this report.
|
(d) |
Shares
issued upon settlement of the purchase contracts, which were a component
of the adjustable conversion-rate equity security
units.
|
(e) |
Includes
issuances of common stock of 1.5 million shares during the nine months
ended September 30, 2006, under DRPlus and 401(k)
plans.
|
(f) |
Component
of the adjustable conversion-rate equity security
units.
|
The
following table presents the authorized amounts under Form S-3 shelf
registration statements filed and declared effective for certain Ameren
Companies as of September 30, 2006:
Effective
Date
|
Authorized
Amount
|
Issued
|
Available
|
|||||||||
Ameren
|
June
2004
|
$
|
2,000
|
$
|
459
|
$
|
1,541
|
|||||
UE
|
October
2005
|
1,000
|
260
|
740
|
||||||||
CIPS
|
May
2001
|
250
|
211
|
39
|
Ameren
also has approximately 6.6 million shares of common stock available for issuance
under various other SEC effective registration statements applicable to its
DRPlus and 401(k) plans as of September 30, 2006.
Ameren,
UE and CIPS may sell all or a portion of the remaining securities registered
under their effective registration statements if market conditions and capital
requirements warrant such a sale. Any offer and sale will be made only by means
of a prospectus meeting the requirements of the Securities Act of 1933 and
the
rules and regulations thereunder.
Indebtedness
Provisions and Other Covenants
See
Note
3 - Credit Facilities and Liquidity to our financial statements under Part
I,
Item 1, of this report for a discussion of the covenants and provisions
contained in our bank credit facilities and applicable cross-default provisions.
Also see Note 4 - Long-term Debt and Equity Financings
to our financial statements under Part I, Item 1, of this report for a
discussion of covenants and provisions contained in certain of the Ameren
Companies’ indenture agreements and articles of incorporation.
At
September 30, 2006, the Ameren Companies were in compliance with their credit
facility, indenture, and articles of incorporation provisions and covenants.
We
consider access to short-term and long-term capital markets a significant source
of funding for capital requirements not satisfied by our operating cash flows.
Our inability to raise capital on favorable terms, particularly during times
of
uncertainty in the capital markets, could negatively affect our ability to
maintain and expand our businesses. After assessing our current operating
performance, liquidity, and credit ratings (see Credit Ratings below), we
believe that we
75
will
continue to have access to the capital markets. However, events beyond our
control, such as the extension of the electric rate freeze in Illinois for
CIPS,
CILCO and IP, may create uncertainty in the capital markets. Such events would
likely increase our cost of capital and adversely affect our ability to access
the capital markets. See Note 2 - Rate and Regulatory Matters to our financial
statements under Part I, Item 1, of this report.
Dividends
Dividends
paid by Ameren to shareholders during the first nine months of 2006 totaled
$391
million, or $1.905 per share (2005 - $383 million or $1.905 per share).
CILCO
paid preferred stock dividends of less than $1 million on October 2, 2006.
IP
paid preferred stock dividends of approximately $1 million on November 1, 2006.
The next preferred dividends are payable on November 15, 2006, December 29,
2006, January 2, 2007, and February 1, 2007, for UE, CIPS, CILCO and IP,
respectively.
See
Note
3 - Credit Facilities and Liquidity and Note 4 - Long-term Debt and Equity
Financings to our financial statements under Part I, Item 1, of this report
for
a discussion of covenants and provisions contained in certain of the Ameren
Companies’ financial agreements, articles of incorporation and an ICC order that
would restrict the Ameren Companies’ payment of dividends in certain
circumstances. At September 30, 2006, except as discussed below with respect
to
the $500 million credit facility, none of these circumstances existed at the
other Ameren Companies and as a result, they were allowed to pay dividends.
On
July
14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a new $500 million
multiyear, senior secured credit facility. This facility limits CIPS, CILCORP,
CILCO or IP to capital stock dividend payments of $10 million per year each
if
CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first
mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have a
below investment-grade senior unsecured credit rating as defined in the new
$500
million facility. With respect to AERG, which currently is not rated, the
dividend restriction will not apply if its consolidated total debt to
consolidated operating cash flow pursuant to a calculation defined in the
facility is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded
CILCORP’s senior unsecured credit rating to below investment-grade causing it to
be subject to this dividend payment limitation. As of September 30, 2006, AERG
failed to meet the debt-to-operating cash flow ratio test in the facility and,
therefore is limited in its ability to pay dividends to a maximum of $10 million
per fiscal year. The other borrowers are not currently limited in their dividend
payments by this provision of the new credit facility. See Note 3 - Credit
Facilities and Liquidity to our financial statements under Part I, Item 1,
of
this report.
The
following table presents dividends paid by Ameren Corporation and by Ameren’s
subsidiaries to their respective parents for the nine months ended September
30,
2006 and 2005.
Nine
Months
|
||||||
2006
|
2005
|
|||||
UE
|
$
|
154
|
$
|
209
|
||
CIPS
|
50
|
21
|
||||
Genco
|
93
|
59
|
||||
CILCORP(a)
|
50
|
30
|
||||
IP
|
-
|
60
|
||||
Nonregistrants
|
44
|
4
|
||||
Dividends
paid by Ameren
|
$
|
391
|
$
|
383
|
(a) |
CILCO
paid dividends of $65 million and $20 million for the nine months
ended
September 30, 2006 and 2005,
respectively.
|
Contractual
Obligations
For
a
complete listing of our obligations and commitments, see Contractual Obligations
under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part
II,
Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the
fiscal year ended December 31, 2005, and Other Obligations in Note 8 -
Commitments and Contingencies under Part I, Item 1, of this report. See Note
11
- Retirement Benefits to our financial statements under Part I, Item 1, of
this
report for information regarding expected minimum funding levels for our pension
plan.
Subsequent
to December 31, 2005, obligations related to the procurement of coal and natural
gas changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $3,986 million,
$1,419 million, $484 million, $601 million, $624 million, $624 million and
$615
million, respectively, as of September 30, 2006. Total other obligations at
September 30, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were
$4,439 million, $1,673 million, $615 million, $601 million, $736 million, $736
million and $797 million, respectively.
76
Credit
Ratings
S&P
On
October 5, 2006, S&P, in reaction to the intensified political discussion in
Illinois regarding electric rate freeze extension legislation, downgraded the
principal credit ratings of the Ameren Companies as presented in the following
table:
From
|
To
|
|
Ameren:
|
||
Corporate
credit rating
|
BBB+
|
BBB
|
Unsecured
debt
|
BBB
|
BBB-
|
Commercial
paper
|
A-2
|
A-3
|
UE:
|
||
Corporate
credit rating
|
BBB+
|
BBB
|
Secured
debt
|
BBB+
|
BBB
|
Unsecured
debt
|
BBB
|
BBB-
|
Preferred
stock
|
BBB-
|
BB+
|
Commercial
paper
|
A-2
|
A-3
|
Genco:
|
||
Corporate
credit rating
|
BBB+
|
BBB
|
Unsecured
debt
|
BBB+
|
BBB
|
CIPS:
|
||
Corporate
credit rating
|
BBB+
|
BBB-
|
Secured
debt
|
A-
|
BBB
|
Unsecured
debt
|
BBB
|
BB+
|
Preferred
stock
|
BBB-
|
BB
|
CILCORP:
|
||
Corporate
credit rating
|
BBB+
|
BBB-
|
Unsecured
debt
|
BBB
|
BB+
|
CILCO:
|
||
Corporate
credit rating
|
BBB+
|
BBB-
|
Secured
debt
|
A-
|
BBB
|
Preferred
stock
|
BBB-
|
BB
|
IP:
|
||
Corporate
credit rating
|
BBB+
|
BBB-
|
Secured
debt
|
BBB+
|
BBB-
|
Preferred
stock
|
BBB-
|
BB
|
All
of
the S&P credit ratings for the Ameren Companies remain on credit watch with
negative implications. According to S&P, it will continue to lower the
Ameren Companies credit ratings if, in its opinion, the likelihood of Illinois
legislation extending the electric rate freeze increases and if the legislation
is passed, they will lower ratings on CIPS, CILCO, CILCORP and IP into the
“B”
category - a deep junk credit rating category.
Moody’s
On
July
26, 2006, Moody’s downgraded the principal credit ratings of certain of the
Ameren Companies as presented in the following table:
From
|
To
|
|
UE:
|
||
Secured
debt
|
A1
|
A2
|
Issuer
rating
|
A2
|
A3
|
Commercial
paper
|
P-1
|
P-2
|
CIPS:
|
||
Secured
debt
|
A3
|
Baa2
|
Unsecured
debt and issuer rating
|
Baa1
|
Baa3
|
CILCORP:
|
||
Unsecured
debt
|
Baa3
|
Ba1
|
CILCO:
|
||
Secured
debt
|
A3
|
Baa1
|
Issuer
rating
|
Baa1
|
Baa2
|
According
to Moody’s, the downgrade of CIPS, CILCORP and CILCO was principally because of
the following factors:
· |
A
difficult political and regulatory environment in Illinois associated
with
the recovery of higher purchased power costs by electric utilities
commencing January 1, 2007.
|
· |
Moody’s
expectation that the outcome in Illinois will involve a material
regulatory deferral of recovery of higher power procurement
costs.
|
Moody’s
confirmed the credit ratings of Ameren and IP, and Genco was unaffected.
According to Moody’s, the downgrade of UE was principally because of the
following factors:
· |
Weaker
financial metrics due to higher operating costs and large capital
expenditures for environmental
compliance.
|
· |
The
likelihood that if the operating cash flow for Ameren’s Illinois utilities
declines, Ameren may need to rely on UE and Ameren’s unregulated
operations for a larger share of upstreamed dividends to meet parent
company obligations.
|
On
October 10, 2006, Moody’s placed the long-term credit ratings of Ameren, UE,
CIPS, Genco, CILCORP, CILCO and IP under review for possible downgrade, and
affirmed the commercial paper ratings of Ameren and UE. Moody’s had removed the
review for possible downgrade as part of its July 2006 actions. According to
Moody’s, the review for possible downgrade was reinstituted by concerns that the
timely recovery of increased utility costs may be impaired by legislative action
in Illinois, specifically the rate freeze legislation discussed in Note 2 -
Rate
and Regulatory Matters to our financial statements under Part I, Item 1, of
this
report. Moody’s stated that enactment of the rate freeze legislation in Illinois
would be expected to result in a multi-notch downgrade of the ratings of CIPS,
CILCORP, CILCO and IP to speculative (sub-investment) grade, reflecting the
severe impact such action would have on the utilities’ cash flow and
liquidity. Moody's has also indicated that upon rate freeze legislation,
or similar legislation that restricts the recovery of costs in a timely manner,
passing the Illinois House of Representatives (even if prior to passage in
the
Illinois Senate or enactment into law), it may consider additional credit
ratings downgrades with regard to one or more of the Ameren
Companies.
Fitch
On
October 10, 2006, Fitch placed the credit ratings of Ameren, CIPS, CILCORP,
CILCO and IP on rating watch negative. The ratings of UE and Genco were affirmed
and not affected by these rating actions. The negative rating watch resulted
from the heightened political rhetoric surrounding
77
future
utility rates in Illinois and uncertainty related to recovery of CIPS’,
CILCORP’s, CILCO’s and IP’s purchased power costs.
Any
adverse change in the Ameren Companies’ credit ratings may reduce access to
capital. It may also increase the cost
of
borrowing and fuel, power and gas supply, among other things, resulting in
a
negative impact on earnings. For example, if at September 30, 2006, the Ameren
Companies had a sub-investment-grade rating (less than BBB- or Baa3), Ameren,
UE, CIPS, Genco, CILCORP, CILCO or IP could have been required to post
collateral or prepay for certain trade obligations amounting to $234 million,
$21 million, $24 million, $10 million, $43 million, $43 million, or $123
million, respectively. In addition, the cost of borrowing under our credit
facilities can increase or decrease depending upon the credit ratings of
the
borrower and suppliers may request prepayment for products and services.
A
credit rating is not a recommendation to buy, sell or hold securities. It
should
be evaluated independently of any other rating. Ratings are subject to revision
or withdrawal at any time by the rating organization.
OUTLOOK
Below
are
some key trends that may affect the Ameren Companies’ financial condition,
results of operations, or liquidity in 2006 and beyond:
Revenues
· |
By
the end of 2006, electric rates for Ameren’s operating subsidiaries will
have been fixed or declining for periods ranging from 15 years to
25
years. In 2006, electric rate adjustment moratoriums and power supply
contracts expire in Ameren’s regulatory jurisdictions. In
January 2006, the ICC approved a framework for CIPS, CILCO and IP
to
procure power for use by their customers in 2007 through an auction.
This
approval is subject to court appeals. The power procurement auction
was
held at the beginning of September 2006. On September 14, 2006, the
ICC
determined that it would not investigate the results of the auction
to
procure power for fixed-price customers, which include the vast majority
of electric customers of CIPS, CILCO and IP. On September 15, 2006,
the
independent auction manager (NERA Economic Consulting) declared a
successful result in the auction for fixed-price customers. The auction
clearing price was approximately $65 per megawatthour for the fixed-price
residential and small commercial product and approximately $85 per
megawatthour for large commercial and industrial customers. Marketing
Company participated in the auction with power being acquired
from Genco and AERG, subject to an auction rules limitation of
providing no more than 35% of a utility’s load, and was awarded sales in
the auction. As a result of the large commercial and industrial customers’
auction price, it is expected that nearly all of these customers
will
choose a different supplier.
|
· |
Power
supplied by Genco and AERG to CIPS and CILCO, respectively, has been
subject to below-market-priced contracts. Most of Genco’s other wholesale
and retail electric power supply agreements also expire during 2006
and
substantially all of these are below market prices for similar contracts
in 2006. In 2005, Genco sold 3.3 million net megawatthours of power
in the
interchange market at an average market price of $47 per megawatthour.
Genco currently expects to generate approximately 17.5 million
megawatthours of power in 2007. By 2007, only 5.2 million megawatthours
of
Genco’s power will be covered by wholesale and retail electric power
supply agreements that were in effect in 2005. These agreements have
an
average embedded selling price of $36 per megawatthour. All other
power
supply agreements in effect in 2005 will expire by the end of 2006
and any
available generation in 2007 will be sold at prevailing market prices.
AERG currently expects to generate approximately 7.0 million megawatthours
of power in 2007. In 2005, this power was sold principally to CILCO
at an
average price of $32 per megawatthour. In addition, AERG sold 1 million
net megawatthours of power in the interchange market at an average
price
of $38 per megawatthour in 2005. In 2007, all of AERG’s power will be sold
at prevailing market prices. Market prices on power supply contracts
entered into by Marketing Company with power being acquired from
Genco and
AERG for sales for 2007 and beyond may vary from the Illinois auction
price based on the contract type, when the contracts were entered
into,
and load shape of customers served under those contracts, among other
things.
|
· |
CIPS,
CILCO and IP filed rate cases with the ICC in December 2005 to modify
their electric delivery service rates effective January 2, 2007.
CIPS,
CILCO and IP requested to increase their annual revenues for electric
delivery service by $202 million in the aggregate (CIPS - $14 million,
CILCO - $43 million and IP - $145 million). Since most customers
are
currently taking service under a frozen bundled electric rate,
which includes the cost of power, any delivery service revenue change
may
not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or
earnings when all customers transition to an electric delivery service
rate effective January 2, 2007. To mitigate the impact of these requested
increases on residential customers, CILCO and IP proposed a two-year
phase-in with increases for average residential delivery rates capped
in
the first year. The phase-in would decrease requested rate increases
by
$10 million and $36 million for CILCO and IP, respectively, in the
first
year. In June 2006, the ICC staff filed rebuttal testimony recommending
increases in revenues for
|
78
electric delivery services for the Ameren Illinois
utilities aggregating $120 million (CIPS - $1 million, CILCO - $30
million
and IP - $89 million). In testimony, the Illinois attorney general
accepted certain of the Ameren Illinois utilities’ positions increasing
its estimated aggregate recommended revenue increase from $70 million
to approximately $110 million (CIPS - $3 million decrease, CILCO
- $29 million increase and IP - $84 million increase). Other parties
also
made recommendations in the cases. In October 2006, the administrative
law
judges issued a proposed order, which included a recommended revenue
increase for electric delivery service of $147 million in the aggregate
(CIPS - $8 million, CILCO - $29 million and
IP - $110
million). The ICC has until November 25, 2006, to render a decision
in
these cases.
|
· |
Ameren
expects the average residential electric rates for CIPS, CILCO and
IP to
increase significantly following the expiration of a rate freeze
at the
end of 2006. Electric rates are expected to rise as a result of increased
cost of power to be purchased on behalf of Ameren Illinois utilities’
customers based on the results of the Illinois power procurement
auction
held in early September 2006 and potential increases resulting from
delivery service cases that are currently pending before the ICC.
CIPS and
IP residential rates are expected to increase approximately 40 percent
over present rates, and CILCO residential rates are expected to increase
approximately 55 percent over present rates. The amount of the actual
increase will depend on outcomes for CIPS’, CILCO’s and IP’s pending
electric delivery services revenue increase requests to the ICC,
among
other things.
|
· |
Due
to the magnitude of these increases, certain Illinois legislators,
the
Illinois attorney general, the Illinois governor and other parties
sought
to block the power procurement auction and continue to challenge
the
auction and/or the recovery of costs for power supply resulting from
the
auction through rates to customers. CIPS, CILCO and IP have received
favorable rulings from the ICC and the Circuit Court of Cook County,
Illinois on opposition claims filed by the Illinois attorney general,
CUB
and ELPC.
|
· |
On
October 2, 2006, Speaker of the Illinois House of Representatives,
Michael
Madigan, sent a letter to Illinois Governor Rod Blagojevich asking
the
Illinois governor to call a special session of the Illinois General
Assembly for the purpose of considering this rate freeze legislation.
In
response, the Illinois governor sent a letter indicating that once
the
votes to pass the legislation were in place he would immediately
call for
a special session of the legislature. The governor’s letter further
provided that in the event a consensus among members of the General
Assembly is not reached in the near future, he would call a special
session in that event as well. The governor’s letter stated he continued
to support legislation extending a rate freeze and would like to
sign it
into law as soon as possible. On October 9, 2006, the Electric Utility
Oversight Committee of the Illinois House of Representatives voted
in
favor of extending the electric rate freeze through 2010. The measure
will
need to be approved by the full Illinois House of Representatives
and
Illinois Senate and signed by the Illinois governor before it can
become
law.
|
· |
CIPS,
CILCO and IP believe the proposed electric rate freeze extension
would
have a material adverse effect on the results of operations, financial
position and liquidity, including the financial insolvency of CIPS,
CILCORP, CILCO and IP, significant job losses and, without governmental
intervention, significant disruptions in electric and gas service.
Since
Ameren’s Illinois utilities own almost no generation, the companies must
purchase power from the competitive market to provide customers’ energy
needs. If the rate freeze were extended, the Ameren Illinois utilities
estimate they would spend in the aggregate approximately $1 billion
annually more for power than they could charge their customers (CIPS
-
$415 million, CILCO - $175 million, IP - $410 million). It is likely
that
the Ameren Illinois utilities’ credit ratings would be downgraded to deep
junk status if rate freeze legislation was enacted. Moody's has also
indicated that upon rate freeze legislation, or similar legislation
that
restricts the recovery of costs in a timely manner, passing the Illinois
House of Representatives (even if prior to passage in the Illinois
Senate
or enactment into law), it may consider additional credit ratings
downgrades with regard to one or more of the Ameren
Companies.
|
· |
With
such credit ratings, CIPS, CILCORP, CILCO and IP would be faced with
potential collateral and prepayment requirements and would quickly
run out
of cash and available credit and be unable to borrow. We believe
this
would lead to the Ameren Illinois utilities being financially insolvent
by
February 2007, or sooner. Any decision or action that impairs the
ability
of CIPS, CILCO, and IP to fully recover costs from their electric
customers in a timely manner would result in material adverse consequences
for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCORP, CILCO and
IP
expect to take whatever actions are necessary to protect their financial
interests, including seeking the protection of the bankruptcy
courts.
|
· |
CIPS,
CILCORP, CILCO and IP strongly believe that an extension of the electric
rate freeze in Illinois would not be in the best interests of any
of the
Ameren Illinois utilities or their customers and have been working
with
key stakeholders in Illinois to develop a constructive rate increase
phase-in plan for residential and small to mid-size commercial customers
to address the significant increases in customer rates for the Ameren
Illinois utilities beginning in 2007. The Ameren Illinois utilities
believe that a rate increase phase-in plan would need to allow for
deferral of a portion of the power procurement
|
79
costs, with provision for full and timely recovery of all deferred costs in a manner that supports investment-grade credit ratings for CIPS, CILCO and IP. CIPS, CILCO and IP filed two proposed plans with the ICC to mitigate the impact of expected higher electric rates for residential customers. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of the proposed plans. |
· |
In
July 2006, UE filed requests with the MoPSC for an increase in electric
rates of $361 million and in natural gas delivery rates of $11 million.
The MoPSC staff and other stakeholders will review UE’s rate adjustment
requests and, after their analyses, may also make recommendations
as to
rate adjustments. Generally, a proceeding to change rates in Missouri
could take up to 11 months. See Note 2 - Rate and Regulatory Matters
to
our financial statements under Part I, Item 1, of this
report.
|
· |
UE,
Genco and CILCO are seeking to raise the equivalent availability
and
capacity factors of their power plants through a process improvement
program.
|
· |
Very
volatile power prices in the Midwest affect the amount of revenues
UE,
Genco and CILCO (through AERG) can generate by marketing power into
the
wholesale and interchange markets and influence the cost of power
we
purchase in the interchange markets. These companies expect to hedge
85%
to 90% of estimated available 2007 generation by the end of
2006.
|
· |
On
April 1, 2005, the MISO Day Two Energy Market began operating. The
MISO
Day Two Energy Market presents an opportunity for increased power
sales
from UE, Genco and CILCO power plants and improved access to power
for UE,
CIPS, CILCO and IP.
|
Fuel
and Purchased Power
· |
In
2005, 86% of Ameren’s electric generation (UE - 80%, Genco - 96%, CILCO -
99%) was supplied by its coal-fired power plants. About 88% of the
coal
used by these plants (UE - 96%, Genco - 67%, CILCO - 77%) was
delivered by railroads from the Powder River Basin in Wyoming. In
2005,
deliveries from the Powder River Basin were restricted due to derailments,
and while coal inventories are currently adequate, deliveries are
still
below desired levels because of railroad capacity limitations. Disruptions
in coal deliveries could cause UE, Genco and CILCO to pursue a strategy
that could include reducing sales of power during low-margin periods,
utilizing higher-cost fuels to generate required electricity and
purchasing power.
|
· |
Ameren’s
coal and related transportation costs are expected to increase 10%
to 15%
in 2006 and approximately
20% in 2007. Ameren’s nuclear fuel costs are expected to rise over the
next few years. In 2007, nuclear fuel costs are expected to increase
by
13% to 18%. In addition, power generation from higher-cost gas-fired
plants is expected to increase in the next few years. See Item 3
-
Quantitative and Qualitative Disclosures about Market Risk of this
report
for information about the percentage of fuel and transportation
requirements that are price-hedged for 2006 through
2010.
|
· |
In
Illinois, we will also experience higher year-over-year purchased
power
expenses as the amortization of certain favorable purchase accounting
adjustments associated with the IP acquisition is
completed.
|
· |
The
MISO Day Two Energy Market resulted in significantly higher MISO-related
costs in 2005. In part, these higher charges were due to volatile
summer
weather patterns and related loads. In addition, we attribute some
of
these higher charges to the relative infancy of the MISO Day Two
Energy
Market, suboptimal dispatching of power plants, and price volatility.
We
will continue to optimize our operations and work closely with MISO
to
ensure that the MISO Day Two Energy Market operates more efficiently
and
effectively in the future.
|
· |
In
July 2005, a new law was enacted that enables the MoPSC to put in
place fuel, purchased power, and environmental cost recovery mechanisms
for Missouri’s utilities. The law also includes rate case filing
requirements, a 2.5% annual rate increase cap for the environmental
cost
recovery mechanism, and prudency reviews, among other things. Rules
for
the fuel and purchased power cost recovery mechanism were approved
by the
MoPSC on September 21, 2006, and are expected to be effective by
the end
of the year. We are unable to predict when rules implementing the
environmental cost recovery mechanism will be formally proposed and
adopted. UE requested fuel, purchased power and environmental cost
recovery mechanisms in its electric rate case filed with the MoPSC
in July
2006. UE’s requests are subject to approval by the
MoPSC.
|
· |
In
the fourth quarter of 2006, Ameren expects to continue selling excess
emission allowances, but in 2007, Ameren expects to reduce levels
of
emission allowance sales in order to retain remaining allowances
for
future compliance needs.
|
Other
Costs
· |
In
December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk
pumped-storage hydroelectric facility. This resulted in significant
flooding in the local area, which damaged a state park. The facility
will
remain out of service until reviews by state authorities are concluded,
further analyses are completed, and input
|
80
is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least all of 2008, if not longer. UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach, including rebuilding the plant, will be covered by insurance. UE expects the total cost for damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $70 million to $90 million. As of September 30, 2006, UE had paid $38 million and accrued a $32 million liability, while expensing $18 million, and recording a $40 million receivable due from insurance companies. As of September 30, 2006, UE has received $12 million from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE may be subject to litigation by private parties or by state authorities. Until the reviews conducted by state authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized. |
· |
UE’s
Callaway nuclear plant’s next scheduled refueling and maintenance outage
is in 2007 and is expected to last 30 to 35 days. During an outage,
which
occurs every 18 months, maintenance and purchased power costs increase,
and the amount of excess power available for sale decreases, versus
non-outage years.
|
· |
Over
the next few years, we expect rising employee benefit costs as well
as
higher insurance and security costs associated with additional measures
we
have taken, or may need to take, at UE’s Callaway nuclear plant and our
other facilities. Insurance premiums may also increase as a result
of the
Taum Sauk incident, among other
things.
|
· |
Bad
debts may increase due to rising electric
rates.
|
· |
We
are currently undertaking cost reduction and control initiatives
associated with the strategic sourcing of purchases and streamlining
of
all aspects of our business.
|
Capital
Expenditures
· |
The
EPA has issued more stringent emission limits on all coal-fired power
plants. Between 2006 and 2016, Ameren expects that certain Ameren
Companies will be required to invest between $2.7 billion and $3.4
billion
to retrofit their power plants with pollution control equipment.
More
stringent state regulations could increase these costs. These investments
will also result in higher ongoing operating expenses. Approximately
50%
of this investment will be in Ameren’s regulated UE operations, and
therefore it is expected to be recoverable from ratepayers. The
recoverability of amounts expended in non-rate-regulated operations
will
depend on whether market prices for power adjust as a result of this
increased investment.
|
· |
UE
continues to evaluate its longer-term needs for new baseload and
peaking
electric generation capacity. At this time, UE does not expect to
require
new baseload generation capacity until at least 2018. However, due
to the
significant time required to plan, acquire permits for and build
a
baseload power plant, UE is actively studying future plant alternatives,
including those utilizing coal or nuclear
power.
|
Affiliate
Transactions
· |
Due
to a MoPSC order issued in conjunction with the transfer of UE’s Illinois
service territory to CIPS, UE, CIPS, and Genco amended the JDA effective
in January 2006. If such an amendment had been in effect in 2005,
we
believe it would have resulted in a transfer of electric margins
from
Genco to UE of $35 million to $45 million based on certain assumptions
and
historical results. In July 2006, UE, CIPS and Genco mutually consented
to
waive the one-year termination notice requirement and agreed to terminate
the JDA on December 31, 2006. As a result of the termination of the
JDA,
UE and Genco will no longer have the obligation to provide power
to each
other. UE will retain the power it was transferring under the JDA
to Genco
at incremental cost and be able to sell any excess power it has at
market
prices, which will most likely be higher. Genco will no longer receive
the
margins on sales that it made, which were supplied with power from
UE.
Ameren’s and UE’s earnings will be affected by the termination of the JDA
when UE’s rates are adjusted by the MoPSC. UE’s requested electric rate
increase filed in July 2006 is net of the decrease in its revenue
requirement resulting from increased margins expected to result from
the
termination of the JDA. See Note 2 - Rate and Regulatory Matters
and Note
7 - Related Party Transactions to our financial statements under
Part I,
Item 1, of this report for a discussion of the modification to the
JDA
ordered by the MoPSC and the effects of terminating the
JDA.
|
· |
On
December 31, 2005, a power supply agreement with EEI for UE, CIPS
(which
resold its entitlement to Marketing Company) and IP expired. Power
supplied under the agreement by EEI to UE, Marketing Company and
IP was
priced at EEI’s cost-based rates. Power previously supplied under this
agreement to UE,
|
81
Marketing Company and IP is being sold at market prices in 2006, which are above EEI’s cost-based rates and will continue to be sold at market prices in 2007. However, in 2006, UE, Genco (which supplies Marketing Company) and IP are replacing power previously received from EEI either through the use of their own higher-cost generation or higher-cost power purchases. In 2005, EEI generated 7.9 million megawatthours of power. UE, CIPS (which resold the power to Marketing Company) and IP purchased 3.0 million, 2.0 million and 1.2 million megawatthours, respectively, from EEI at an average price of $20 per megawatthour. The remaining generation was sold to EEI’s minority owner. The expiration of this agreement and the resulting decrease in UE’s margins and increase in its revenue requirement were reflected in UE’s July 2006 request to the MoPSC to increase electric rates. |
Recent
Acquisitions
· |
Ameren,
CILCORP, CILCO and IP expect to focus on realizing integration synergies
associated with these acquisitions, including utilizing more economical
fuels at CILCORP and CILCO and reducing administrative and operating
expenses at IP.
|
Other
· |
Ameren
expects to complete the sale of some leveraged lease investments
in
2006.
|
· |
In
August 2005, President George W. Bush signed into law the Energy
Policy
Act of 2005. This legislation includes several provisions that affect
the Ameren Companies, including the repeal of PUHCA 1935 (under which
Ameren was registered) effective in February 2006, and tax incentives
for
investments in pollution control equipment, electric transmission
property, clean coal facilities, and natural gas distribution
lines. The Energy Policy Act of 2005 also extends the Price-Anderson
nuclear plant liability provisions under the Atomic Energy Act of
1954.
|
The
above
items could have a material impact on our results of operations, financial
position, or liquidity. Additionally, in the ordinary course of business, we
evaluate strategies to enhance our results of operations, financial position,
or
liquidity. These strategies may include acquisitions, divestitures,
opportunities to reduce costs or increase revenues, and other strategic
initiatives to increase Ameren’s shareholder value. We are unable to predict
which, if any, of these initiatives will be executed. The execution of these
initiatives may have a material impact on our future results of operations,
financial position, or liquidity.
REGULATORY
MATTERS
See
Note
2 - Rate and Regulatory Matters to our financial statements under Part I, Item
1, of this report.
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK.
Market
risk is the risk of changes in value of a physical asset or a financial
instrument, derivative or non-derivative, caused by fluctuations in market
variables such as interest rates, commodity prices and equity security prices.
A
derivative is a contract whose value is dependent on, or derived from, the
value
of some underlying asset. We
handle
market risks in accordance with established policies, which may include entering
into various derivative transactions. In the normal course of business, we
also
face risks that are either nonfinancial or nonquantifiable. Such risks,
principally business, legal and operational risks, are not part of the following
discussion.
Our
risk
management objective is to optimize our physical generating assets within
prudent risk parameters. Our risk management policies are set by a Risk
Management Steering Committee, which is comprised of senior-level Ameren
officers.
Except
as
discussed below, there have been no material changes to the quantitative and
qualitative disclosures about market risk in the Ameren Companies’ combined
Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See
Item
7A under Part II of the 2005 Form 10-K for a more detailed discussion of our
market risks.
Interest
Rate Risk
We
are
exposed to market risk through changes in interest rates. The following table
presents the estimated increase in our annual interest expense and decrease
in
net income if interest rates were to increase by 1% on variable-rate debt
outstanding at September 30, 2006:
Interest
Expense
|
Net
Income(a)
|
|||||
Ameren
|
$
|
13
|
$
|
(8
|
)
|
|
UE
|
6
|
(4
|
)
|
|||
CIPS
|
(b
|
)
|
(b
|
)
|
||
Genco
|
2
|
(1
|
)
|
|||
CILCORP
|
3
|
(2
|
)
|
|||
CILCO
|
1
|
(1
|
)
|
|||
IP
|
4
|
(3
|
)
|
(a) |
Calculations
are based on an effective tax rate of 38%.
|
(b) |
Less
than $1 million.
|
82
The
model
does not consider potential reduced overall economic activity that would
exist
in such an environment. In the event of a significant change in interest
rates,
management would probably act to further mitigate our exposure to this market
risk. However, due to the uncertainty of the specific actions that would
be
taken and their possible effects, this sensitivity analysis assumes no change
in
our financial structure.
Credit
Risk
Credit
risk represents the loss that would be recognized if counterparties fail to
perform as contracted. NYMEX-traded futures contracts are supported by the
financial and credit quality of the clearing members of the NYMEX and have
nominal credit risk. On all other transactions, we are exposed to credit risk
in
the event of nonperformance by the counterparties to the
transaction.
Our
physical and financial instruments are subject to credit risk consisting of
trade accounts receivables, executory contracts with market risk exposures,
and
leveraged lease investments. The risk associated with trade receivables is
mitigated by the large number of customers in a broad range of industry groups
who make up our customer base. At September 30, 2006, no nonaffiliated customer
represented greater than 10%, in the aggregate, of our accounts receivable.
Our
revenues are primarily derived from sales of electricity and natural gas to
customers in Missouri and Illinois. UE, Genco, AERG, IP and Marketing Company
may have credit exposure associated with interchange purchase and sale activity
with nonaffiliated companies. At September 30, 2006, UE’s, Genco’s, AERG’s, IP’s
and Marketing Company’s combined credit exposure to non-investment-grade
counterparties related to interchange purchases and sales was less than $1
million, net of collateral. We establish credit limits for these counterparties
and monitor the appropriateness of these limits on an ongoing basis through
a
credit risk management program that involves daily exposure reporting to senior
management, master trading and netting agreements, and credit support, such
as
letters of credit and parental guarantees. We also analyze each counterparty’s
financial condition before we enter into sales, forwards, swaps, futures or
option contracts, and we monitor counterparty exposure associated with our
leveraged leases. We estimate our credit exposure to MISO associated with the
MISO Day Two Energy Market to be $35 million at September 30, 2006.
Equity
Price Risk
Our
costs
of providing defined benefit retirement and postretirement plans are dependent
on a number of factors, including the rate of return on plan assets. To the
extent the value of plan assets declines, the effect would be reflected in
net
income and OCI, and in the amount of cash required to be contributed to the
plans.
Commodity
Price Risk
We
are
exposed to changes in market prices for electricity, fuel, and natural gas.
UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are
partially hedged through sales agreements to regulated and nonregulated electric
customers. Most of Genco’s and AERG’s electric power sales agreements expire
during 2006. EEI’s cost-based power supply agreements for nearly all of its
power expired at the end of 2005. EEI has an agreement to sell 100% of its
capacity and energy to Marketing Company through December 31, 2015. EEI plans
to
hedge for price risk up to 80% of its available megawatthours. Genco and AERG
participated jointly in the September 2006 Illinois power procurement auction
through Marketing Company. Genco and AERG will also seek to sell power forward
to wholesale, municipal and industrial customers as has been their past
practice. By December 31, 2006, Genco and AERG will seek to hedge for price
risk
85% to 90% of estimated available megawatthours for 2007 by December 31, 2006.
We also attempt to mitigate financial risks through structured risk management
programs and policies, which include structured forward-hedging programs and
the
use of derivative financial instruments (primarily forward contracts, futures
contracts, option contracts, and financial swap contracts).
CIPS,
CILCO and IP have electric rate freezes in Illinois through January 1, 2007,
and
power supply contracts in place through December 31, 2006. In January 2006,
the
ICC approved the Ameren Illinois utilities’ proposed power procurement auction
and the related tariffs for the period commencing January 2, 2007, including
the
retail rates by which power supply costs would be passed through to customers.
The power procurement auction was held at the beginning of September 2006.
Marketing Company was awarded sales in the auction. UE’s electric rate freeze in
Missouri expired June 30, 2006. In July 2006, UE filed for an increase in
electric rates, including a request for a fuel, purchased power and
environmental cost recovery mechanism. UE is also exposed to price risk on
its
interchange sales. See Note 2 - Rate and Regulatory Matters to our financial
statements under Part I, Item 1, of this report for further
information.
83
The
following table presents the percentages of the projected required supply of
coal and coal transportation for our coal-fired power plants, nuclear fuel
for
UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution,
as
appropriate, and purchased power needs of CIPS, CILCO and IP, which own
virtually no generation, that are price-hedged over the remainder of 2006
through 2010:
2006
|
2007
|
2008
-
2010
|
|||||||
Ameren:
|
|||||||||
Coal
|
100
|
%
|
100
|
%
|
65
|
%
|
|||
Coal
transportation
|
100
|
95
|
60
|
||||||
Nuclear
fuel
|
100
|
100
|
70
|
||||||
Natural
gas for generation
|
100
|
26
|
2
|
||||||
Natural
gas for distribution(a)
|
(a
|
)
|
46
|
10
|
|||||
UE:
|
|||||||||
Coal
|
100
|
%
|
100
|
%
|
61
|
%
|
|||
Coal
transportation
|
100
|
99
|
79
|
||||||
Nuclear
fuel
|
100
|
100
|
70
|
||||||
Natural
gas for generation
|
100
|
6
|
1
|
||||||
Natural
gas for distribution(a)
|
(a
|
)
|
52
|
9
|
|||||
CIPS:
|
|||||||||
Natural
gas for distribution(a)
|
(a
|
)
|
56
|
%
|
19
|
%
|
|||
Purchased
power(b)
|
100
|
100
|
47
|
||||||
Genco:
|
|||||||||
Coal
|
100
|
%
|
100
|
%
|
76
|
%
|
|||
Coal
transportation
|
100
|
95
|
40
|
||||||
Natural
gas for generation
|
100
|
47
|
5
|
||||||
CILCORP/CILCO:
|
|||||||||
Coal
|
100
|
%
|
100
|
%
|
63
|
%
|
|||
Coal
transportation
|
100
|
69
|
44
|
||||||
Natural
gas for distribution(a)
|
(a
|
)
|
44
|
9
|
|||||
Purchased
power(b)
|
100
|
100
|
47
|
||||||
IP:
|
|||||||||
Natural
gas for distribution(a)
|
(a
|
)
|
43
|
%
|
8
|
%
|
|||
Purchased
power(b)
|
90
|
100
|
47
|
(a) |
Represents
the percentage of natural gas price-hedged for the peak winter season
of
November through March. The year 2006 represents the period January
2006
through March 2006 and therefore is non-applicable for this report.
The
year 2007 represents November 2006 through March 2007. This continues
each
successive year through March 2010.
|
(b) |
Represents
the percentage of purchased power price-hedged for fixed-price residential
and small commercial customers with less than 1 megawatt of demand
as part
of the Illinois power procurement auction held in early September
2006. Excluded from the percent hedged amount is purchased power for
fixed-price large commercial and industrial customers with 1 megawatt
of
demand or higher who have 30 to 50 days after the date the auction
was
declared successful (September 15, 2006) to elect not to receive
power
from CIPS, CILCO or IP. However, regardless of whether customers
choose a third-party supplier, the purchased power needed to serve
this
load is 100% price-hedged through May 31, 2008 due to the Illinois
auction. Also excluded from the percent hedged amount is purchased
power to serve large service real-time pricing customers as the auction
results have not been finalized for this customer class. See Note 2 -
Rate and Regulatory Matters and Note 8 - Commitments and Contingencies
to
our financial statements under Part I, Item 1, of this report for
a
discussion of this matter.
|
The
following table shows how our total fuel expense might increase and how our
net
income might decrease if coal and coal transportation costs were to increase
by
1% on any requirements not currently covered by fixed-price contracts for the
remainder of 2006 through 2010:
Coal
|
Transportation
|
||||||||||||
Fuel
Expense
|
Net
Income(a)
|
Fuel
Expense
|
Net
Income(a)
|
||||||||||
Ameren
|
$
|
6
|
$
|
(4
|
)
|
$
|
11
|
$
|
(7
|
)
|
|||
UE
|
4
|
(2
|
)
|
3
|
(2
|
)
|
|||||||
Genco
|
1
|
(1
|
)
|
4
|
(3
|
)
|
|||||||
CILCORP/CILCO
|
1
|
(b
|
)
|
2
|
(1
|
)
|
(a) |
Calculations
are based on an effective tax rate of
38%.
|
(b) |
Less
than $1 million.
|
In
the
event of a significant change in coal prices, UE, Genco and CILCO would probably
take actions to further mitigate their exposure to this market risk. However,
due to the uncertainty of the specific actions that would be taken and their
possible effects, this sensitivity analysis assumes no change in our financial
structure or fuel sources. As discussed in Note 2 - Rate and Regulatory Matters
under Part I, Item 1, of this report, Missouri legislation has been approved
that could mitigate the impact of increased fuel cost at Ameren and UE through
UE’s ability to recover these increases in rates.
See
Note
8 - Commitments and Contingencies to our financial statements under Part I,
Item
1, of this report for further information regarding the long-term commitments
for the procurement of coal, natural gas and nuclear fuel.
84
Fair
Value of Contracts
Most
of
our commodity contracts qualify for treatment as normal purchases and normal
sales. We use derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. The following
table presents the favorable (unfavorable) changes in the fair value of all
derivative contracts marked-to-market during the three months and nine months
ended September 30, 2006. The sources used to determine the fair value of these
contracts were active quotes, other external sources, and other modeling and
valuation methods. All of these contracts have maturities of less than five
years.
Ameren(a)
|
UE
|
CIPS
|
Genco
|
CILCORP/
CILCO
|
IP
|
||||||||||||||
Three
Months
|
|||||||||||||||||||
Fair
value of contracts at beginning of period, net
|
$
|
43
|
$
|
(2
|
)
|
$
|
4
|
$
|
1
|
$
|
18
|
$
|
2
|
||||||
Contracts
realized or otherwise settled during the period
|
(14
|
)
|
(1
|
)
|
(1
|
)
|
(1
|
)
|
(6
|
)
|
-
|
||||||||
Changes
in fair values attributable to changes in valuation technique and
assumptions
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||
Fair
value of new contracts entered into during the period
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||
Other
changes in fair value
|
34
|
8
|
(1
|
)
|
2
|
(3
|
)
|
2
|
|||||||||||
Fair
value of contracts outstanding at end of period, net
|
$
|
63
|
$
|
5
|
$
|
2
|
$
|
2
|
$
|
9
|
$
|
4
|
|||||||
Nine
Months
|
|||||||||||||||||||
Fair
value of contracts at beginning of period, net
|
$
|
69
|
$
|
(5
|
)
|
$
|
12
|
$
|
-
|
$
|
50
|
$
|
(2
|
)
|
|||||
Contracts
realized or otherwise settled during the period
|
(40
|
)
|
(5
|
)
|
(6
|
)
|
-
|
(15
|
)
|
(2
|
)
|
||||||||
Changes
in fair values attributable to changes in valuation technique and
assumptions
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||
Fair
value of new contracts entered into during the period
|
1
|
1
|
-
|
-
|
-
|
-
|
|||||||||||||
Other
changes in fair value
|
33
|
14
|
(4
|
)
|
2
|
(26
|
)
|
8
|
|||||||||||
Fair
value of contracts outstanding at end of period, net
|
$
|
63
|
$
|
5
|
$
|
2
|
$
|
2
|
$
|
9
|
$
|
4
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
ITEM
4. CONTROLS AND PROCEDURES.
(a) |
Evaluation
of Disclosure Controls and
Procedures
|
As
of
September 30, 2006, the principal executive officer and principal financial
officer of each of the Ameren Companies have evaluated the effectiveness of
the
design and operation of each registrant’s disclosure controls and procedures (as
defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Upon making
that evaluation, the principal executive officer and principal financial officer
of each of the Ameren Companies have concluded that such disclosure controls
and
procedures are effective in timely alerting them to any material information
relating to such registrant that is required in such registrant’s reports filed
or submitted to the SEC under the Exchange Act, and are effective in ensuring
that information required to be disclosed in reports filed under the Exchange
Act is recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms.
(b) |
Change
in Internal Controls
|
There
has
been no change in the Ameren Companies’ internal control over financial
reporting during their most recent fiscal quarter that has materially affected,
or is reasonably likely to materially affect, their internal control over
financial reporting.
PART
II. OTHER INFORMATION
ITEM
1. LEGAL PROCEEDINGS.
We
are
involved in legal and administrative proceedings before various courts and
agencies with respect to matters that arise in the ordinary course of business,
some of which involve sub-stantial amounts of money. We believe that the final
disposition of these proceedings, except as otherwise disclosed in this report,
will not have a material adverse effect on our results of operations, financial
position, or liquidity. Risk of loss is mitigated, in some cases, by insurance
or contractual or statutory indemnification. We believe that we have established
appropriate reserves for potential losses.
Note
2 -
Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note 8
-
Commitments and Contingencies to our financial statements under Part I, Item
1,
of this report contain information on legal and administrative proceedings
which
are incorporated by reference under this item.
85
ITEM
1A. RISK FACTORS.
The
Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended
December 31, 2005, includes a detailed discussion of our risk factors. The
information presented below updates and should be read in conjunction with
the
risk factors and information disclosed in that Form 10-K.
The
electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are
currently the subject of rate case proceedings and potential legislative action.
The outcome of these proceedings and potential legislative action is largely
outside of our control. Should these events result in the inability of UE,
CIPS,
CILCO or IP to recover their respective costs, it could have a material adverse
effect on our future results of operations, financial position or liquidity.
In
particular, we believe a proposed electric rate freeze extension in Illinois
would lead to CIPS, CILCORP, CILCO and IP being financially insolvent by
February 2007, or sooner.
The
rates
that certain Ameren Companies are allowed to charge for their services are
the
single most important item influencing the results of operations, financial
position, or liquidity of the Ameren Companies. Our industry is highly
regulated. The regulation of the rates that we charge our customers is
determined, in large part, by governmental entities outside of our control,
including the MoPSC, the ICC, and FERC. Decisions made by these entities could
have a material adverse effect on our results of operations, financial position
or liquidity.
Increased
costs and investments, when combined with rate reductions and moratoriums,
have
caused decreased returns in Ameren’s utility businesses. Ameren expects many of
its operating expenses will continue to rise and further expects to continue
to
make significant investment in its energy infrastructure, which are the
principal factors underlying its pending rate increase requests with the MoPSC
and the ICC. We cannot predict the outcome of these rate case proceedings or
potential Illinois legislative action to extend the rate freeze. In addition,
in
response to competitive, economic, political, legislative and regulatory
pressures, in connection with the resolution of our current rate case
proceedings, or otherwise, we may be subject to further rate moratoriums, rate
refunds, limits on rate increases or rate reductions, including phase-in plans.
Any or all of these could have a material adverse effect on our results of
operations, financial position or liquidity.
Illinois
Electric
Delivery Rate Cases
A
provision of the Illinois Customer Choice Law related to the restructuring
of
the Illinois electric industry put a rate freeze into effect through
January 1, 2007, for CIPS, CILCO and IP. CIPS, CILCO and IP filed rate
cases with the ICC in December 2005 to modify their electric delivery service
rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their
annual revenues for electric delivery service by $202 million in the aggregate
(CIPS - $14 million, CILCO - $43 million and IP - $145 million). Since most
customers are currently taking service under a frozen bundled electric
rate, which includes the cost of power, any delivery service revenue change
may
not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or
earnings when all customers transition to an electric delivery service rate
effective January 2, 2007. To mitigate the impact of these requested increases
on residential customers, CILCO and IP proposed a two-year phase-in with
increases for average residential delivery rates capped in the first year.
The
phase-in would decrease requested rate increases by $10 million and $36 million
for CILCO and IP, respectively, in the first year. In June 2006, the ICC staff
filed rebuttal testimony recommending increases in revenues for electric
delivery services for the Ameren Illinois utilities aggregating $120 million
(CIPS - $1 million, CILCO - $30 million and IP - $89 million). In testimony,
the
Illinois attorney general recommended an aggregate revenue increase of
approximately $110 million (CIPS - $3 million decrease, CILCO - $29 million
increase and IP - $84 million increase). Other parties also made recommendations
in the cases. In October 2006, the administrative law judges issued a proposed
order, which included a recommended revenue increase for electric delivery
service of $147 million in the aggregate (CIPS - $8 million, CILCO - $29 million
and IP - $110 million). The ICC has until November 25, 2006, to render a
decision in these cases. Without appropriate and timely rate relief, any new
energy infrastructure investment could result in increased financing
requirements for CIPS, CILCO and IP. The lack of full and timely recovery of
these costs could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s
and IP’s results of operations, financial position or liquidity.
Potential
Extension of Illinois Electric Rate Freeze and Recovery of Post-2006 Power
Supply Costs
Consistent
with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO
and IP through January 1, 2007, these companies entered into power supply
contracts that expire on December 31, 2006. In January 2006, the ICC approved
a
framework for CIPS, CILCO and IP to procure power for use by their customers
86
through
a
power procurement auction and the related tariffs to collect these costs from
customers for the period commencing January 2, 2007. This approval is subject
to
pending court appeals. In accordance with the January 2006 ICC order, a power
procurement auction was held in September 2006. Subsequently, the ICC determined
that it would not investigate the results of the auction to procure power for
fixed-price customers, and the independent auction manager declared a successful
result in the auction for these fixed-price customers, which include the vast
majority of electric customers of CIPS, CILCO and IP. Certain Illinois
legislators, the Illinois attorney general, the Illinois governor, and other
parties sought to block the power procurement auction and continue to challenge
the auction and/or the recovery of costs for power supply resulting from the
auction through rates to customers. In February 2006, legislation was introduced
in the Illinois House of Representatives that would extend the electric rate
freeze in Illinois through 2010. On October 2, 2006, Speaker of the
Illinois House of Representatives, Michael Madigan, sent a letter to Illinois
Governor Rod Blagojevich asking the Illinois governor to call a special session
of the Illinois General Assembly for the purpose of considering this rate freeze
legislation. In response, the Illinois governor sent a letter indicating that
once the votes to pass the legislation were in place he would immediately call
for a special session of the legislature. The governor’s letter further provided
that in the event a consensus among members of the General Assembly is not
reached in the near future, he would call a special session in that event as
well. The governor’s letter stated he continued to support legislation extending
the rate freeze and would like to sign it into law as soon as possible. On
October 9, 2006, the Electric Utility Oversight Committee of the Illinois House
of Representatives voted in favor of extending the electric rate freeze through
2010. The measure will need to be approved by the full Illinois House of
Representatives and Illinois Senate, and signed by the Illinois governor before
it can become law.
CIPS,
CILCORP, CILCO and IP believe the proposed electric rate freeze legislation,
if
enacted, would have a material adverse effect on their results of operations,
financial position and liquidity, including the financial insolvency of CIPS,
CILCORP, CILCO and IP, as well as result in significant job losses and, without
governmental intervention, significant disruptions in electric and gas service.
Since Ameren’s Illinois utilities own almost no generation, the companies must
purchase power from the competitive market to provide customers’ energy needs.
If the rate freeze were extended, the Ameren Illinois utilities estimate they
would spend in the aggregate approximately $1 billion annually more for power
than they could charge their customers (CIPS - $415 million, CILCO - $175
million, IP - $410 million). The major credit rating agencies have stated that
the Ameren Illinois utilities’ and CILCORP’s credit ratings would be downgraded
to deep junk status if rate freeze extension legislation is enacted. Moody's
has
also indicated that upon rate freeze legislation, or similar legislation that
restricts the recovery of costs in a timely manner, passing the Illinois House
of Representatives (even if prior to passage in the Illinois Senate or enactment
into law), it may consider additional credit ratings downgrades with regard
to
one or more of the Ameren Companies.With such credit ratings, we believe CIPS,
CILCORP, CILCO and IP would be faced with potential collateral and prepayment
requirements for products and services, such as power and natural gas, and
would
quickly run out of cash and available credit and be unable to borrow. We believe
this would lead to the Ameren Illinois utilities and CILCORP being financially
insolvent by February 2007, or sooner. In reaction to intensified political
discussion in Illinois regarding electric rate freeze extension legislation,
in
October 2006, S&P downgraded the short- and long-term credit ratings of the
Ameren Companies and kept the Ameren Companies on credit watch with negative
implications; Moody’s placed the long-term debt ratings of the Ameren Companies
under review for possible downgrade; and Fitch placed the ratings of Ameren,
CIPS, CILCORP, CILCO and IP on rating watch negative.
CIPS,
CILCO and IP strongly believe that an extension of the electric rate freeze
in
Illinois would not be in the best interests of any of the Ameren Illinois
utilities or their customers and have been working with key stakeholders in
Illinois to develop a constructive rate increase phase-in plan for residential
customers to address the significant increases in customer rates for the Ameren
Illinois utilities beginning in 2007. The Ameren Illinois utilities believe
that
a rate increase phase-in plan would need to allow for deferral of a portion
of
the power procurement costs, with provision for full and timely recovery of
all
deferred costs in a manner that supports investment-grade credit ratings for
CIPS, CILCO and IP. However, even a rate phase-in plan that does not allow
for
the full and timely recovery of our costs could have a material adverse effect
on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position
or liquidity.
Ameren,
CIPS, CILCO and IP will continue to explore a number of legal and regulatory
actions, strategies and alternatives to address these Illinois electric issues.
CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to
protect their legal and financial interests, including seeking the protection
of
the bankruptcy courts. However, there can be no assurance that Ameren and the
Ameren Illinois utilities will prevail over the stated opposition of certain
Illinois legislators, the Illinois attorney general, the Illinois governor,
and
other stakeholders, or that the legal and regulatory actions, strategies and
87
alternatives
that Ameren and the Ameren Illinois
utilities are considering will be successful.
We
are
unable to predict the results of the court appeals of the ICC order approving
CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, nor
can we predict the actions the Illinois General Assembly and governor may
take
which may impact electric rates or the
power
procurement process for CIPS, CILCO and IP after the expiration of the current
Illinois electric rate freeze on January 1, 2007, and power supply contracts
on
December 31, 2006. Any decision or action that impairs the ability of CIPS,
CILCO and IP to fully recover purchased power costs from their electric
customers in a timely manner would result in material adverse consequences
to
Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a
significant drop in credit ratings to deep junk status, a loss of access
to the
capital markets, higher borrowing costs, higher power supply costs, an inability
to make timely energy infrastructure investments, significant risk of disruption
in electric and gas service, significant job losses, and financial insolvency.
In addition, Ameren, CILCORP and IP could be required to record a charge
for
goodwill impairment related to goodwill that was recorded when Ameren acquired
these companies. As of September 30, 2006, Ameren, CILCORP and IP had $976
million, $575 million and $326 million, respectively, of goodwill on their
balance sheets. Furthermore, if the Ameren Illinois utilities are unable
to
recover their costs from customers, the utilities could be required to cease
applying SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation”, which allows CIPS, CILCORP, CILCO and IP to defer certain costs
pursuant to actions of rate regulators and to recover such costs in rates
charged to customers. This would result in the elimination of all regulatory
assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and
a
one-time extraordinary charge on their statements of income that could be
material. As of September 30, 2006, CIPS, CILCORP, CILCO and IP had $35 million,
$12 million, $12 million and $197 million, respectively, recorded as regulatory
assets on their balance sheets.
Missouri
With
the
expiration of multi-year electric and gas rate moratoriums, effective July
1,
2006, UE filed requests with the MoPSC in July 2006 for an increase in electric
rates of
$361
million and for an increase in natural gas delivery rates of $11 million. The
MoPSC staff and other stakeholders will review UE’s rate adjustment requests
and, after their analyses, may also make recommendations as to electric and
gas
rate adjustments. A decision from the MoPSC is expected no later than June
2007.
UE
does
not currently have a rate adjustment clause in Missouri for its electric
operations that would allow it to recover the costs for purchased power,
increased fuel or infrastructure investment costs from customers. Therefore,
insofar as UE has not hedged its fuel and power costs, UE is exposed to changes
in fuel and power prices to the extent they exceed the costs embedded in current
rates. In its Missouri electric rate case filed in July 2006, UE requested
a
fuel and purchased power cost recovery mechanism, which is still subject to
MoPSC approval. UE also requested an environmental cost recovery mechanism
as
part of its current Missouri electric rate case, but rules have not been
established for such a mechanism. Without appropriate and timely rate relief,
any new energy infrastructure investment could result in increased financing
requirements for UE. The lack of timely recovery of these costs could have
a
material adverse effect on UE’s results of operations, financial position or
liquidity.
If
the Illinois electric rate freeze is extended or the ability of CIPS, CILCO
and
IP to recover post-2006 power supply costs or increase electric delivery service
rates that are the subject of pending rate cases is otherwise impaired, there
may be a material adverse effect on Ameren, UE and Genco in addition to the
Ameren Illinois utilities and CILCORP.
We
believe the proposed rate freeze extension in Illinois, if enacted, would lead
to CIPS, CILCORP, CILCO and IP being financially insolvent by February 2007,
or
sooner. Although the Ameren Companies are separate, independent legal entities
with separate businesses, assets and liabilities, there is a risk that the
financial insolvency of CIPS, CILCORP, CILCO and IP could have a materially
adverse effect on Ameren, UE and Genco. In the event of an extension of the
electric rate freeze in Illinois for CIPS, CILCO and IP, or subsequent financial
insolvency of these companies, such events might increase Ameren’s, UE’s and
Genco’s cost of capital or adversely affect the ability of these companies to
access the capital markets, particularly during times of uncertainty in the
capital markets, which could negatively affect their ability to maintain and
expand their businesses. Moody’s, S&P and Fitch have each indicated that
they would lower the credit ratings for CIPS, CILCORP, CILCO and IP to deep
junk
status if the electric rate freeze was extended reflecting the material impact
such action would have on the cash flow and liquidity of these companies. It
is
possible that the rating agencies could decide to lower the credit ratings
of
Ameren, UE or Genco at the same time. Any adverse change in the ratings of
Ameren, UE or Genco could also increase the cost of borrowing under credit
facilities and suppliers may request prepayment for products and services (such
as fuel, power and gas) or the posting of collateral.
88
Commitments
or amounts due from CIPS, CILCORP, CILCO and IP to Ameren, UE, and Genco
may be
unfulfilled or unpaid in the event of financial insolvency of these companies.
In connection with the recent Illinois power procurement auction, Marketing
Company agreed to sell power to CIPS, CILCO and IP that is expected to be
supplied under contracts from Genco and AERG. In the event of the insolvency
of
CIPS, CILCORP, CILCO and IP, Genco, AERG or Marketing Company may not be
able to
recover the cost of power delivered to CIPS, CILCO and IP but
not
paid for prior to insolvency. Marketing Company’s commitments to sell power to
CIPS, CILCO, IP and other unaffiliated parties also rely, in part, on power
supplied by AERG. In the event of financial insolvency, AERG may not be able
to
deliver power it has committed to sell to Marketing Company potentially
requiring Marketing Company to acquire power to meet its commitments at a
higher
cost.
In
addition, dividends on Ameren’s common stock and the payment of Ameren’s other
obligations, including its debt, depend on distributions made to it by its
subsidiaries. In the event that CIPS, CILCORP, CILCO and IP become
insolvent, they will not be able to make distributions to Ameren. As a result,
the board of directors of Ameren may decide to rely more heavily on UE and
Ameren’s unregulated operations to support dividends on Ameren’s common stock,
or reduce or eliminate the payment of dividends. Moreover, the absence of
distributions from the Illinois utilities and CILCORP could force Ameren to
use
other available sources of liquidity to service its debt
obligations.
We
cannot
determine at this time whether the proposed rate freeze extension in Illinois
that would lead to CIPS, CILCORP, CILCO and IP being financially insolvent
by
February 2007, or sooner, will occur. We also cannot determine what the
resulting effect would be on Ameren, UE and Genco. However, the financial
insolvency of CIPS, CILCO and IP could have a material adverse effect on the
results of operations, financial position or liquidity of Ameren, UE and
Genco.
Our
counterparties may not meet their obligations to us.
We
are
exposed to the risk that counterparties to various arrangements (including
our
affiliates) who owe us money, energy, coal or other commodities or services
will
not be able to perform their obligations. Should the counterparties to these
arrangements fail to perform, we might be forced to replace or to sell the
underlying commitment at then-current market prices. In such event, we might
incur losses or our results of operations, financial position or liquidity
could
otherwise be adversely affected.
In
connection with the expiration of existing power supply agreements at the end
of
2006, the ICC approved a framework for electric utilities in Illinois, including
CIPS, CILCO and IP, to procure power for use by their customers in 2007 through
a power procurement auction and related tariffs, including the retail rates
by
which power supply costs would be passed through to customers. Commencing in
2007, Genco and AERG will be selling power previously sold under expiring
contracts to Marketing Company, which sold power through the Illinois power
procurement auction to CIPS, CILCO and IP and is selling power through other
contracts with wholesale and retail customers. If the attempts by certain
Illinois legislators, the Illinois attorney general, the Illinois governor
and
other parties to block the ability of CIPS, CILCO and IP to recover post-2006
power supply costs are successful, thereby triggering the financial insolvency
of CIPS, CIILCORP, CILCO, and IP, Genco, AERG and Marketing Company may not
be
able to recover payment for power delivered to CIPS, CILCO and IP pursuant
to
the Illinois power procurement auction. An inability to recover such payments
could have a material adverse effect on the results of operations, financial
position, or liquidity of Ameren, Genco, AERG, and Marketing Company. In the
event of the subsequent termination of the power supply contracts between
Marketing Company and CIPS, CILCO and IP, Marketing Company would need to resell
at then-current market prices the power previously committed to CIPS, CILCO
and
IP. We cannot predict whether there would be buyers for Marketing Company’s
power or what the market prices will be at the time of any such sales.
89
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS.
The
following table presents Ameren Corporation’s purchases of equity securities
reportable under Item 703 of Regulation S-K:
Period
|
(a)
Total Number
of
Shares
(or
Units)
Purchased(a)
|
(b)
Average Price
Paid
per Share
(or
Unit)
|
(c)
Total Number of Shares (or Units) Purchased as Part of Publicly Announced
Plans or Programs
|
(d)
Maximum Number (or Approximate Dollar Value) of Shares (or Units)
that May
Yet Be Purchased Under the Plans or Programs
|
||||||||
July
1 - July 31, 2006
|
1,950
|
$
|
50.84
|
-
|
-
|
|||||||
August
1 - August 31, 2006
|
3,800
|
52.78
|
-
|
-
|
||||||||
September
1 - September 30, 2006
|
-
|
-
|
-
|
-
|
||||||||
Total
|
5,750
|
$
|
52.12
|
-
|
-
|
(a) |
These
shares of Ameren common stock were purchased in open-market transactions
in satisfaction of Ameren’s obligation upon the exercise by employees of
options issued under Ameren’s Long-term Incentive Plan of
1998. Ameren does not have any publicly announced equity securities
repurchase plans or programs.
|
The
following table presents CILCO’s purchases of equity securities reportable under
Item 703 of Regulation S-K:
Period
|
(a)
Total Number
of
Shares
(or
Units)
Purchased(a)
|
(b)
Average Price
Paid
per Share
(or
Unit)
|
(c)
Total Number of Shares (or Units) Purchased as Part of Publicly Announced
Plans or Programs
|
(d)
Maximum Number (or Approximate Dollar Value) of Shares (or Units)
that May
Yet Be Purchased Under the Plans or Programs
|
|||||||||
July
1 - July 31, 2006
|
11,000
|
$
|
100.00
|
-
|
-
|
||||||||
August
1 - August 31, 2006
|
-
|
-
|
-
|
-
|
|||||||||
September
1 - September 30, 2006
|
-
|
-
|
-
|
-
|
|||||||||
Total
|
11,000
|
$
|
100.00
|
-
|
-
|
(a) |
CILCO
redeemed these shares of its 5.85% Class A preferred stock to satisfy
the
mandatory sinking fund redemption requirement for this series of
preferred
stock for 2006. CILCO does not have any publicly announced equity
securities repurchase plans or
programs.
|
None
of
the other registrants purchased equity securities reportable under Item 703
of
Regulation S-K during the July 1 to September 30, 2006 period.
ITEM
6. EXHIBITS.
(a)
Exhibits. The documents listed below are being filed on behalf of Ameren, UE,
CIPS, Genco, CILCORP, CILCO and IP as indicated.
Exhibit
Designation
|
Registrant(s)
|
Nature
of Exhibit
|
|
Instruments
Defining Rights of Security Holders
|
|||
*4.1
|
CILCO
|
Registration
Rights Agreement, dated as of June 14, 2006, among CILCO, Citigroup
Global
Markets, Inc. and Goldman, Sachs & Co., as representatives of the
Initial Purchasers (as defined therein) (incorporated by reference
to
Exhibit 4(d) to CILCO’s Form S-4, File No. 333-137449)
|
|
*4.2
|
IP
|
Registration
Rights Agreement, dated as of June 14, 2006, among IP, Goldman,
Sachs
& Co. and Lehman Brothers, Inc., as representatives of the Initial
Purchasers (as defined therein) (incorporated by reference to Exhibit
4(d)
to IP’s Form S-4, File No. 333-137448)
|
|
Statement
re: Computation of Ratios
|
|||
12.1
|
Ameren
|
Ameren’s
Statement of Computation of Ratio of Earnings to Fixed Charges
|
|
12.2
|
UE
|
UE’s
Statement of Computation of Ratio of Earnings to Fixed Charges
and
Combined Fixed Charges and Preferred Stock Dividend
Requirements
|
|
12.3
|
CIPS
|
CIPS’
Statement of Computation of Ratio of Earnings to Fixed Charges
and
Combined Fixed Charges and Preferred Stock Dividend
Requirements
|
|
12.4
|
Genco
|
Genco’s
Statement of Computation of Ratio of Earnings to Fixed
Charges
|
|
12.5
|
CILCORP
|
CILCORP’s
Statement of Computation of Ratio of Earnings to Fixed
Charges
|
|
12.6
|
CILCO
|
CILCO’s
Statement of Computation of Ratio of Earnings to Fixed Charges
and
Combined Fixed Charges and Preferred Stock Dividend
Requirements
|
90
Exhibit
Designation
|
Registrant(s) |
Nature
of Exhibit
|
|
12.7
|
IP
|
IP’s
Statement of Computation of Ratio of Earnings to Fixed Charges
and
Combined Fixed Charges and Preferred Stock Dividend
Requirements
|
|
Rule
13a-14(a) / 15d-14(a) Certifications
|
|||
31.1
|
Ameren
|
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren | |
31.2
|
Ameren
|
Rule
13a-14(a)/15d-14(a) Certification of Principal Financial Officer
of
Ameren
|
|
31.3 |
UE
CIPS
CILCORP
CILCO
IP
|
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE, CIPS, CILCORP, CILCO and IP | |
31.4
|
UE
CIPS
Genco
CILCORP
CILCO
IP
|
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE, CIPS, Genco, CILCORP, CILCO and IP | |
31.5
|
Genco
|
Rule
13a-14(a)/15d-14(a) Certification of Principal Executive Officer
of
Genco
|
|
Section
1350 Certifications
|
|||
32.1
|
Ameren
UE
CIPS
CILCORP
CILCO
IP
|
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren, UE, CIPS, CILCORP, CILCO and IP | |
32.2
|
Genco
|
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco |
*
Incorporated by reference herein as indicated.
91
SIGNATURES
Pursuant
to the requirements of the Exchange Act, each registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized.
The signature for each undersigned company shall be deemed to relate only to
matters having reference to such company or its subsidiaries.
AMEREN
CORPORATION
(Registrant)
/s/ Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
UNION
ELECTRIC COMPANY
(Registrant)
/s/ Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
/s/ Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
AMEREN
ENERGY GENERATING COMPANY
(Registrant)
/s/ Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
92
CILCORP
INC.
(Registrant)
/s/ Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
CENTRAL
ILLINOIS LIGHT COMPANY
(Registrant)
/s/
Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
ILLINOIS
POWER COMPANY
(Registrant)
/s/ Martin J.
Lyons
Martin
J.
Lyons
Vice
President and Controller
(Principal
Accounting Officer)
Date:
November 9, 2006
93