UNION ELECTRIC CO - Quarter Report: 2006 June (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 June 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
July 31, 2006, was as follows:
Ameren
Corporation
|
Common
stock, $.01 par value per share - 205,866,928
|
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...........................................................................................................................
|
53
|
Item
3. Quantitative
and Qualitative Disclosures About Market
Risk................................................................................................................................................................................
|
72
|
Item
4. Controls
and
Procedures...............................................................................................................................................................................................................................................
|
75
|
PART
II Other
Information
|
|
Item
1. Legal
Proceedings...........................................................................................................................................................................................................................................................
|
75
|
Item
1A Risk
Factors.....................................................................................................................................................................................................................................................................
|
75
|
Item
2. Unregistered
Sales of Equity Securities and Use of
Proceeds.................................................................................................................................................................................
|
77
|
Item
4. Submission
of Matters to a Vote of Security
Holders...............................................................................................................................................................................................
|
78
|
Item
6. Exhibits.............................................................................................................................................................................................................................................................................
|
79
|
Signatures............................................................................................................................................................................................................................................................................................
|
81
|
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 serves as a power marketing
and risk management agent for UE and Genco primarily for transactions of less
than one year.
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 parent,
which primarily develops and constructs generating facilities for
Genco.
DOE
-
Department of Energy, a U.S. government agency.
DRPlus
-
Ameren
Corporation’s dividend reinvestment and direct stock purchase plan.
Dynegy
-
Dynegy
Inc.
EEI
-
Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40% owned
by
UE and 40% owned by Development Company) that operates electric generation
and
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.
Equivalent
availability factor
- A
measure that indicates the percentage of time an electric power generating
unit
was available for service during a specific period.
ERISA
-
Employee Retirement Income Security Act of 1974, as amended.
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 Number. A FIN statement is an explanation intended to clarify
accounting pronouncements previously issued by the FASB.
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.
IP
- Illinois
Power Company, an Ameren Corporation subsidiary that was acquired from Dynegy
on
September 30,
5
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 TFNs 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.
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,
primarily for periods over one year.
Medina
Valley
-
AmerenEnergy Medina
Valley Cogen (No. 4) LLC and its subsidiaries, which are all Development Company
subsidiaries, which 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.
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.
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.
TFN
-
Transitional Funding Trust Notes issued by IP SPT as allowed under Illinois’
deregulation legislation. IP must designate a portion of cash received from
customer billings to pay the TFNs. The proceeds received by IP are remitted
to
IP SPT. The proceeds are restricted for the sole purpose of making payments
of
principal and interest on, and paying other fees and expenses related to, the
TFNs.
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” provi-sions 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 as the outcome of UE, CIPS, CILCO
and IP
rate proceedings;
|
· |
the
impact of the termination of the joint dispatch agreement among UE,
CIPS,
and Genco;
|
6
· |
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 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
AMEREN
CORPORATION
|
|||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
|||||||||||||
(Unaudited)
(In millions, except per share amounts)
|
|||||||||||||
|
|||||||||||||
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
Operating
Revenues:
|
|||||||||||||
Electric
|
$
|
1,378
|
$
|
1,407
|
$
|
2,589
|
$
|
2,529
|
|||||
Gas
|
172
|
174
|
761
|
670
|
|||||||||
Other
|
-
|
3
|
-
|
4
|
|||||||||
Total
operating revenues
|
1,550
|
1,584
|
3,350
|
3,203
|
|||||||||
Operating
Expenses:
|
|||||||||||||
Fuel
and purchased power
|
524
|
485
|
1,049
|
894
|
|||||||||
Gas
purchased for resale
|
104
|
106
|
557
|
460
|
|||||||||
Other
operations and maintenance
|
394
|
375
|
742
|
720
|
|||||||||
Depreciation
and amortization
|
162
|
157
|
327
|
314
|
|||||||||
Taxes
other than income taxes
|
90
|
95
|
203
|
186
|
|||||||||
Total
operating expenses
|
1,274
|
1,218
|
2,878
|
2,574
|
|||||||||
Operating
Income
|
276
|
366
|
472
|
629
|
|||||||||
Other
Income and Expenses:
|
|||||||||||||
Miscellaneous
income
|
4
|
6
|
8
|
13
|
|||||||||
Miscellaneous
expense
|
(1
|
)
|
(6
|
)
|
(1
|
)
|
(7
|
)
|
|||||
Total
other income
|
3
|
-
|
7
|
6
|
|||||||||
Interest
Charges
|
80
|
77
|
156
|
151
|
|||||||||
Income
Before Income Taxes, Minority Interest
|
|||||||||||||
and
Preferred Dividends of Subsidiaries
|
199
|
289
|
323
|
484
|
|||||||||
Income
Taxes
|
68
|
100
|
112
|
171
|
|||||||||
Income
Before Minority Interest and Preferred
|
|||||||||||||
Dividends
of Subsidiaries
|
131
|
189
|
211
|
313
|
|||||||||
Minority
Interest and Preferred Dividends
|
|||||||||||||
of
Subsidiaries
|
(8
|
)
|
(4
|
)
|
(18
|
)
|
(7
|
)
|
|||||
Net
Income
|
$
|
123
|
$
|
185
|
$
|
193
|
$
|
306
|
|||||
Earnings
per Common Share – Basic and Diluted
|
$
|
0.60
|
$
|
0.93
|
$
|
0.94
|
$
|
1.55
|
|||||
Dividends
per Common Share
|
$
|
0.635
|
$
|
0.635
|
$
|
1.27
|
$
|
1.27
|
|||||
Average
Common Shares Outstanding
|
205.4
|
199.7
|
205.1
|
197.5
|
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)
|
|||||||
June
30,
|
December
31,
|
||||||
2006
|
2005
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$
|
51
|
$
|
96
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $25 and $22, respectively)
|
409
|
552
|
|||||
Unbilled
revenue
|
355
|
382
|
|||||
Miscellaneous
accounts and notes receivable
|
71
|
31
|
|||||
Materials
and supplies
|
549
|
572
|
|||||
Other
current assets
|
110
|
185
|
|||||
Total
current assets
|
1,545
|
1,818
|
|||||
Property
and Plant, Net
|
13,920
|
13,572
|
|||||
Investments
and Other Assets:
|
|||||||
Investments
in leveraged leases
|
32
|
50
|
|||||
Nuclear
decommissioning trust fund
|
257
|
250
|
|||||
Goodwill
|
976
|
976
|
|||||
Intangible
assets
|
250
|
246
|
|||||
Other
assets
|
643
|
419
|
|||||
Regulatory
assets
|
827
|
831
|
|||||
Total
investments and other assets
|
2,985
|
2,772
|
|||||
TOTAL
ASSETS
|
$
|
18,450
|
$
|
18,162
|
|||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt
|
$
|
124
|
$
|
96
|
|||
Short-term
debt
|
397
|
193
|
|||||
Accounts
and wages payable
|
404
|
706
|
|||||
Taxes
accrued
|
97
|
131
|
|||||
Other
current liabilities
|
386
|
361
|
|||||
Total
current liabilities
|
1,408
|
1,487
|
|||||
Long-term
Debt, Net
|
5,705
|
5,354
|
|||||
Preferred
Stock of Subsidiary Subject to Mandatory
Redemption
|
19
|
19
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
1,958
|
1,969
|
|||||
Accumulated
deferred investment tax credits
|
123
|
129
|
|||||
Regulatory
liabilities
|
1,173
|
1,132
|
|||||
Asset
retirement obligations
|
531
|
518
|
|||||
Accrued
pension and other postretirement benefits
|
800
|
760
|
|||||
Other
deferred credits and liabilities
|
174
|
218
|
|||||
Total
deferred credits and other liabilities
|
4,759
|
4,726
|
|||||
Preferred
Stock of Subsidiaries Not Subject to Mandatory
Redemption
|
195
|
195
|
|||||
Minority
Interest in Consolidated Subsidiaries
|
15
|
17
|
|||||
Commitments
and Contingencies (Notes 2, 8 and 9)
|
|||||||
Stockholders'
Equity:
|
|||||||
Common
stock, $.01 par value, 400.0 shares authorized,
|
|||||||
205.8
and 204.7 shares outstanding, respectively
|
2
|
2
|
|||||
Other
paid-in capital, principally premium on common stock
|
4,457
|
4,399
|
|||||
Retained
earnings
|
1,932
|
1,999
|
|||||
Accumulated
other comprehensive loss
|
(36
|
)
|
(24
|
)
|
|||
Other
|
(6
|
)
|
(12
|
)
|
|||
Total
stockholders’ equity
|
6,349
|
6,364
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
18,450
|
$
|
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)
|
||||||
|
Six
Months Ended
|
|||||
June
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
193
|
$
|
306
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
340
|
299
|
||||
Amortization
of nuclear fuel
|
16
|
17
|
||||
Amortization
of debt issuance costs and premium/discounts
|
7
|
7
|
||||
Deferred
income taxes and investment tax credits, net
|
(19
|
)
|
66
|
|||
Loss
on sale of leveraged leases
|
4
|
-
|
||||
Minority
interest
|
12
|
1
|
||||
Other
|
1
|
-
|
||||
Changes
in assets and liabilities, excluding the effects of
acquisitions:
|
||||||
Receivables,
net
|
168
|
(8
|
)
|
|||
Materials
and supplies
|
25
|
46
|
||||
Accounts
and wages payable
|
(258
|
)
|
(163
|
)
|
||
Taxes
accrued
|
(33
|
)
|
112
|
|||
Assets,
other
|
58
|
11
|
|
|||
Liabilities,
other
|
10
|
1
|
||||
Pension
and other postretirement benefit obligations, net
|
46
|
54
|
||||
Net
cash provided by operating activities
|
570
|
749
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(406
|
)
|
(442
|
)
|
||
CT
acquisitions
|
(292
|
)
|
-
|
|||
Nuclear
fuel expenditures
|
(25
|
)
|
(13
|
)
|
||
Proceeds
from sale of leveraged leases
|
11
|
-
|
||||
Purchases
of emission allowances
|
(38 | ) | (92 | ) | ||
Sales
of emission allowances
|
4 | 4 | ||||
Other
|
-
|
12
|
||||
Net
cash used in investing activities
|
(746
|
)
|
(531
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(260
|
)
|
(253
|
)
|
||
Capital
issuance costs
|
(2
|
)
|
(1
|
)
|
||
Short-term
debt, net
|
204
|
(256
|
)
|
|||
Dividends
paid to minority interest
|
(14
|
)
|
-
|
|||
Redemptions,
repurchases, and maturities:
|
||||||
Long-term
debt
|
(86
|
)
|
(237
|
)
|
||
Issuances:
|
||||||
Common
stock
|
57
|
402
|
||||
Long-term
debt
|
232
|
85
|
||||
Net
cash provided by (used in) financing activities
|
131
|
(260
|
)
|
|||
Net
change in cash and cash equivalents
|
(45
|
)
|
(42
|
)
|
||
Cash
and cash equivalents at beginning of year
|
96
|
69
|
||||
Cash
and cash equivalents at end of period
|
$
|
51
|
$
|
27
|
||
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
June
30,
|
Six
Months Ended
June
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
687
|
$
|
726
|
$
|
1,254
|
$
|
1,259
|
||||
Gas
|
22
|
26
|
91
|
101
|
||||||||
Other
|
1
|
-
|
1
|
-
|
||||||||
Total
operating revenues
|
710
|
752
|
1,346
|
1,360
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
192
|
182
|
384
|
326
|
||||||||
Gas
purchased for resale
|
12
|
13
|
56
|
58
|
||||||||
Other
operations and maintenance
|
196
|
193
|
367
|
374
|
||||||||
Depreciation
and amortization
|
81
|
76
|
161
|
152
|
||||||||
Taxes
other than income taxes
|
59
|
59
|
118
|
114
|
||||||||
Total
operating expenses
|
540
|
523
|
1,086
|
1,024
|
||||||||
Operating
Income
|
170
|
229
|
260
|
336
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
1
|
2
|
4
|
9
|
||||||||
Miscellaneous
expense
|
(2
|
)
|
(2
|
)
|
(4
|
)
|
(4
|
)
|
||||
Total
other income (expense)
|
(1
|
)
|
-
|
-
|
5
|
|||||||
Interest
Charges
|
37
|
27
|
72
|
52
|
||||||||
Income
Before Income Taxes and Equity
|
||||||||||||
in
Income of Unconsolidated Investment
|
132
|
202
|
188
|
289
|
||||||||
Income
Taxes
|
50
|
71
|
69
|
102
|
||||||||
Income
Before Equity in Income
|
||||||||||||
of
Unconsolidated Investment
|
82
|
131
|
119
|
187
|
||||||||
Equity
in Income of Unconsolidated Investment
|
10
|
1
|
24
|
2
|
||||||||
Net
Income
|
92
|
132
|
143
|
189
|
||||||||
Preferred
Stock Dividends
|
2
|
2
|
3
|
3
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
90
|
$
|
130
|
$
|
140
|
$
|
186
|
||||
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)
|
|||||||
June
30,
|
December
31,
|
||||||
2006
|
2005
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$
|
1
|
$
|
20
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $6 and $6, respectively)
|
141
|
190
|
|||||
Unbilled
revenue
|
176
|
133
|
|||||
Miscellaneous
accounts and notes receivable
|
58
|
7
|
|||||
Accounts
receivable – affiliates
|
26
|
53
|
|||||
Current
portion of intercompany note receivable – CIPS
|
-
|
6
|
|||||
Materials
and supplies
|
214
|
199
|
|||||
Other
current assets
|
49
|
57
|
|||||
Total
current assets
|
665
|
665
|
|||||
Property
and Plant, Net
|
7,696
|
7,379
|
|||||
Investments
and Other Assets:
|
|||||||
Nuclear
decommissioning trust fund
|
257
|
250
|
|||||
Intercompany
note receivable – CIPS
|
-
|
61
|
|||||
Intangible
assets
|
63
|
63
|
|||||
Other
assets
|
496
|
269
|
|||||
Regulatory
assets
|
583
|
590
|
|||||
Total
investments and other assets
|
1,399
|
1,233
|
|||||
TOTAL
ASSETS
|
$
|
9,760
|
$
|
9,277
|
|||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt
|
$
|
11
|
$
|
4
|
|||
Short-term
debt
|
364
|
80
|
|||||
Accounts
and wages payable
|
90
|
274
|
|||||
Accounts
and wages payable – affiliates
|
83
|
134
|
|||||
Taxes
accrued
|
113
|
59
|
|||||
Other
current liabilities
|
148
|
96
|
|||||
Total
current liabilities
|
809
|
647
|
|||||
Long-term
Debt, Net
|
2,931
|
2,698
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
1,293
|
1,277
|
|||||
Accumulated
deferred investment tax credits
|
92
|
96
|
|||||
Regulatory
liabilities
|
811
|
802
|
|||||
Asset
retirement obligations
|
478
|
466
|
|||||
Accrued
pension and other postretirement benefits
|
221
|
203
|
|||||
Other
deferred credits and liabilities
|
56
|
72
|
|||||
Total
deferred credits and other liabilities
|
2,951
|
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
|
734
|
733
|
|||||
Retained
earnings
|
1,744
|
1,689
|
|||||
Accumulated
other comprehensive loss
|
(33
|
)
|
(30
|
)
|
|||
Total
stockholders' equity
|
3,069
|
3,016
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
9,760
|
$
|
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)
|
|||||||
Six
Months Ended
June
30,
|
|||||||
2006
|
2005
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$
|
143
|
$
|
189
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
161
|
152
|
|||||
Amortization
of nuclear fuel
|
16
|
17
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
3
|
3
|
|||||
Deferred
income taxes and investment tax credits, net
|
11
|
30
|
|||||
Other
|
(5
|
)
|
(8
|
)
|
|||
Changes
in assets and liabilities:
|
|||||||
Receivables,
net
|
(15
|
)
|
(114
|
)
|
|||
Materials
and supplies
|
(13
|
)
|
5
|
||||
Accounts
and wages payable
|
(206
|
)
|
(61
|
)
|
|||
Taxes
accrued
|
54
|
111
|
|||||
Assets,
other
|
25
|
(3
|
)
|
||||
Liabilities,
other
|
35
|
11
|
|||||
Pension
and other postretirement benefit obligations, net
|
18
|
21
|
|||||
Net
cash provided by operating activities
|
227
|
353
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(197
|
)
|
(248
|
)
|
|||
CT
acquisitions from non-affiliates
|
(292
|
)
|
-
|
||||
CT
acquisitions from Genco
|
-
|
(241
|
)
|
||||
Nuclear
fuel expenditures
|
(25
|
)
|
(13
|
)
|
|||
Sales
of emission allowances
|
2
|
2 | |||||
Other
|
1
|
8
|
|||||
Net
cash used in investing activities
|
(511
|
)
|
(492
|
)
|
|||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
(84
|
)
|
(135
|
)
|
|||
Dividends
on preferred stock
|
(3
|
)
|
(3
|
)
|
|||
Proceeds
from intercompany note receivable - CIPS
|
67
|
-
|
|||||
Changes
in short-term debt, net
|
284
|
(237
|
)
|
||||
Changes
in money pool borrowings
|
-
|
380
|
|||||
Issuance
of long-term debt
|
-
|
85
|
|||||
Capital
contribution from parent
|
1
|
2
|
|||||
Net
cash provided by financing activities
|
265
|
92
|
|||||
Net
change in cash and cash equivalents
|
(19
|
)
|
(47
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
20
|
48
|
|||||
Cash
and cash equivalents at end of period
|
$
|
1
|
$
|
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
June
30,
|
Six
Months Ended
June
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
181
|
$
|
171
|
$
|
341
|
$
|
299
|
||||
Gas
|
30
|
27
|
127
|
111
|
||||||||
Other
|
1
|
-
|
1
|
-
|
||||||||
Total
operating revenues
|
212
|
198
|
469
|
410
|
||||||||
Operating
Expenses:
|
||||||||||||
Purchased
power
|
113
|
105
|
230
|
191
|
||||||||
Gas
purchased for resale
|
16
|
15
|
88
|
74
|
||||||||
Other
operations and maintenance
|
38
|
37
|
76
|
70
|
||||||||
Depreciation
and amortization
|
15
|
15
|
31
|
28
|
||||||||
Taxes
other than income taxes
|
9
|
7
|
21
|
15
|
||||||||
Total
operating expenses
|
191
|
179
|
446
|
378
|
||||||||
Operating
Income
|
21
|
19
|
23
|
32
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
4
|
4
|
9
|
9
|
||||||||
Miscellaneous
expense
|
-
|
(4
|
)
|
(1
|
)
|
(4
|
)
|
|||||
Total
other income
|
4
|
-
|
8
|
5
|
||||||||
Interest
Charges
|
8
|
8
|
15
|
15
|
||||||||
Income
Before Income Taxes
|
17
|
11
|
16
|
22
|
||||||||
Income
Taxes
|
2
|
4
|
2
|
7
|
||||||||
Net
Income
|
15
|
7
|
14
|
15
|
||||||||
Preferred
Stock Dividends
|
-
|
-
|
1
|
1
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
15
|
$
|
7
|
$
|
13
|
$
|
14
|
||||
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)
|
||||||
June
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
1
|
$
|
-
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $4 and $4, respectively)
|
57
|
70
|
||||
Unbilled
revenue
|
57
|
71
|
||||
Accounts
receivable – affiliates
|
11
|
18
|
||||
Current
portion of intercompany note receivable – Genco
|
37
|
34
|
||||
Current
portion of intercompany tax receivable – Genco
|
10
|
10
|
||||
Advances
to money pool
|
17
|
-
|
||||
Materials
and supplies
|
54
|
75
|
||||
Other
current assets
|
19
|
28
|
||||
Total
current assets
|
263
|
306
|
||||
Property
and Plant, Net
|
1,141
|
1,130
|
||||
Investments
and Other Assets:
|
||||||
Intercompany
note receivable – Genco
|
126
|
163
|
||||
Intercompany
tax receivable – Genco
|
120
|
125
|
||||
Other
assets
|
15
|
24
|
||||
Regulatory
assets
|
35
|
36
|
||||
Total
investments and other assets
|
296
|
348
|
||||
TOTAL
ASSETS
|
$
|
1,700
|
$
|
1,784
|
||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
-
|
$
|
20
|
||
Accounts
and wages payable
|
26
|
36
|
||||
Accounts
and wages payable – affiliates
|
65
|
65
|
||||
Borrowings
from money pool
|
-
|
2
|
||||
Current
portion of intercompany note payable – UE
|
-
|
6
|
||||
Taxes
accrued
|
7
|
26
|
||||
Other
current liabilities
|
37
|
43
|
||||
Total
current liabilities
|
135
|
198
|
||||
Long-term
Debt, Net
|
471
|
410
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes and investment tax credits, net
|
295
|
302
|
||||
Intercompany
note payable – UE
|
-
|
61
|
||||
Regulatory
liabilities
|
209
|
208
|
||||
Other
deferred credits and liabilities
|
39
|
36
|
||||
Total
deferred credits and other liabilities
|
543
|
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
|
189
|
189
|
||||
Preferred
stock not subject to mandatory redemption
|
50
|
50
|
||||
Retained
earnings
|
316
|
329
|
||||
Accumulated
other comprehensive income (loss)
|
(4
|
)
|
1
|
|||
Total
stockholders' equity
|
551
|
569
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
1,700
|
$
|
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)
|
||||||
Six
Months Ended
June
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
14
|
$
|
15
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
31
|
28
|
||||
Deferred
income taxes and investment tax credits, net
|
(16
|
)
|
(7
|
)
|
||
Other
|
(1
|
)
|
(4
|
)
|
||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
39
|
10
|
||||
Materials
and supplies
|
21
|
7
|
||||
Accounts
and wages payable
|
(9
|
)
|
17
|
|||
Taxes
accrued
|
(19
|
)
|
11
|
|||
Assets,
other
|
22
|
10
|
||||
Liabilities,
other
|
(3
|
)
|
5
|
|||
Pension
and other postretirement benefit obligations, net
|
-
|
4
|
||||
Net
cash provided by operating activities
|
79
|
96
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(40
|
)
|
(24
|
)
|
||
Proceeds
from intercompany note receivable – Genco
|
34
|
52
|
||||
Changes
in money pool advances
|
(17
|
)
|
(28
|
)
|
||
Net
cash used in investing activities
|
(23
|
)
|
-
|
|||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(25
|
)
|
(9
|
)
|
||
Dividends
on preferred stock
|
(1
|
)
|
(1
|
)
|
||
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
|
)
|
-
|
|||
Issuances:
|
||||||
Long-term
debt
|
61
|
-
|
||||
Capital
contribution from parent
|
-
|
1
|
||||
Net
cash used in financing activities
|
(55
|
)
|
(97
|
)
|
||
Net
change in cash and cash equivalents
|
1
|
(1
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
-
|
2
|
||||
Cash
and cash equivalents at end of period
|
$
|
1
|
$
|
1
|
||
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
June
30,
|
Six
Months Ended
June
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
238
|
$
|
266
|
$
|
485
|
$
|
491
|
||||
Total
operating revenues
|
238
|
266
|
485
|
491
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
150
|
138
|
315
|
237
|
||||||||
Other
operations and maintenance
|
47
|
38
|
79
|
76
|
||||||||
Depreciation
and amortization
|
17
|
18
|
35
|
37
|
||||||||
Taxes
other than income taxes
|
5
|
5
|
11
|
3
|
||||||||
Total
operating expenses
|
219
|
199
|
440
|
353
|
||||||||
Operating
Income
|
19
|
67
|
45
|
138
|
||||||||
Other
Income:
|
||||||||||||
Miscellaneous
income
|
-
|
1
|
-
|
1
|
||||||||
Total
other income
|
-
|
1
|
-
|
1
|
||||||||
Interest
Charges
|
15
|
19
|
30
|
40
|
||||||||
Income
Before Income Taxes
|
4
|
49
|
15
|
99
|
||||||||
Income
Taxes
|
2
|
18
|
7
|
37
|
||||||||
Net
Income
|
$
|
2
|
$
|
31
|
$
|
8
|
$
|
62
|
||||
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)
|
|||||||
June
30,
|
December
31,
|
||||||
2006
|
2005
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$
|
1
|
$
|
-
|
|||
Accounts
receivable – affiliates
|
97
|
102
|
|||||
Accounts
receivable
|
7
|
29
|
|||||
Materials
and supplies
|
99
|
73
|
|||||
Other
current assets
|
1
|
1
|
|||||
Total
current assets
|
205
|
205
|
|||||
Property
and Plant, Net
|
1,505
|
1,514
|
|||||
Intangible
Assets
|
90
|
79
|
|||||
Other
Assets
|
13
|
13
|
|||||
TOTAL
ASSETS
|
$
|
1,813
|
$
|
1,811
|
|||
LIABILITIES
AND STOCKHOLDER'S EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
portion of intercompany note payable – CIPS
|
$
|
37
|
$
|
34
|
|||
Borrowings
from money pool
|
260
|
203
|
|||||
Accounts
and wages payable
|
27
|
41
|
|||||
Accounts
and wages payable – affiliates
|
97
|
60
|
|||||
Current
portion of intercompany tax payable – CIPS
|
10
|
10
|
|||||
Taxes
accrued
|
14
|
37
|
|||||
Other
current liabilities
|
23
|
16
|
|||||
Total
current liabilities
|
468
|
401
|
|||||
Long-term
Debt, Net
|
474
|
474
|
|||||
Intercompany
Note Payable – CIPS
|
126
|
163
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
142
|
156
|
|||||
Accumulated
deferred investment tax credits
|
9
|
10
|
|||||
Intercompany
tax payable – CIPS
|
120
|
125
|
|||||
Asset
retirement obligations
|
29
|
29
|
|||||
Accrued
pension and other postretirement benefits
|
11
|
8
|
|||||
Other
deferred credits and liabilities
|
2
|
1
|
|||||
Total
deferred credits and other liabilities
|
313
|
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
|
278
|
228
|
|||||
Retained
earnings
|
157
|
220
|
|||||
Accumulated
other comprehensive loss
|
(3
|
) |
(4
|
)
|
|||
Total
stockholder's equity
|
432
|
444
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDER'S EQUITY
|
$
|
1,813
|
$
|
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)
|
|||||||
Six
Months Ended
June
30,
|
|||||||
2006
|
2005
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$
|
8
|
$
|
62
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
51
|
47
|
|||||
Amortization
of debt issuance costs and discounts
|
-
|
1
|
|||||
Deferred
income taxes and investment tax credits, net
|
(8
|
)
|
16
|
||||
Other
|
(1
|
) |
-
|
||||
Changes
in assets and liabilities:
|
|||||||
Accounts
receivable
|
27
|
(16
|
)
|
||||
Materials
and supplies
|
(26
|
)
|
(6
|
)
|
|||
Accounts
and wages payable
|
28
|
40
|
|||||
Taxes
accrued, net
|
(23
|
)
|
(12
|
)
|
|||
Assets,
other
|
-
|
|
6
|
|
|||
Liabilities,
other
|
(4
|
)
|
(9
|
)
|
|||
Pension
and other postretirement benefit obligations, net
|
3
|
3
|
|||||
Net
cash provided by operating activities
|
55
|
132
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(31
|
)
|
(43
|
)
|
|||
Proceeds
from asset sale to UE
|
-
|
241
|
|||||
Changes
in money pool advances
|
-
|
(26
|
)
|
||||
Purchases
of emission allowances
|
(26 | ) | (71 | ) | |||
Sales
of emission allowances
|
1 | 1 | |||||
Net
cash provided by (used in) investing activities
|
(56
|
)
|
102
|
||||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
(71
|
)
|
(34
|
)
|
|||
Changes
in money pool borrowings
|
57
|
(116
|
)
|
||||
Redemptions,
repurchases, and maturities:
|
|||||||
Intercompany
note payable – CIPS and Ameren
|
(34
|
)
|
(86
|
)
|
|||
Capital
contribution from parent
|
50
|
1
|
|||||
Net
cash provided by (used in) financing activities
|
2
|
(235
|
)
|
||||
Net
change in cash and cash equivalents
|
1
|
(1
|
)
|
||||
Cash
and cash equivalents at beginning of year
|
-
|
1
|
|||||
Cash
and cash equivalents at end of period
|
$
|
1
|
$
|
-
|
|||
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
June
30,
|
Six
Months Ended
June
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
98
|
$
|
100
|
$
|
190
|
$
|
193
|
||||
Gas
|
48
|
46
|
198
|
174
|
||||||||
Other
|
-
|
1
|
-
|
2
|
||||||||
Total
operating revenues
|
146
|
147
|
388
|
369
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
35
|
39
|
61
|
72
|
||||||||
Gas
purchased for resale
|
32
|
29
|
151
|
123
|
||||||||
Other
operations and maintenance
|
48
|
39
|
89
|
81
|
||||||||
Depreciation
and amortization
|
19
|
18
|
41
|
36
|
||||||||
Taxes
other than income taxes
|
4
|
4
|
13
|
11
|
||||||||
Total
operating expenses
|
138
|
129
|
355
|
323
|
||||||||
Operating
Income
|
8
|
18
|
33
|
46
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
1
|
-
|
1
|
-
|
||||||||
Miscellaneous
expense
|
(1
|
)
|
(3
|
)
|
(2
|
)
|
(5
|
)
|
||||
Total
other expenses
|
-
|
(3
|
)
|
(1
|
)
|
(5
|
)
|
|||||
Interest
Charges
|
13
|
13
|
25
|
25
|
||||||||
Income
(Loss) Before Income Taxes & Preferred
|
||||||||||||
Dividends
of Subsidiaries
|
(5
|
)
|
2
|
7
|
16
|
|||||||
Income
Taxes (Benefit)
|
(6
|
)
|
-
|
(3
|
)
|
4
|
||||||
Income
Before Preferred Dividends of Subsidiaries
|
1
|
2
|
10
|
12
|
||||||||
Preferred
Dividends of Subsidiaries
|
-
|
-
|
1
|
1
|
||||||||
Net
Income
|
$
|
1
|
$
|
2
|
$
|
9
|
$
|
11
|
||||
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)
|
|||||||
June
30,
|
December
31,
|
||||||
2006
|
2005
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$
|
23
|
$
|
3
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $6 and $5, respectively)
|
44
|
61
|
|||||
Unbilled
revenue
|
34
|
59
|
|||||
Accounts
receivables – affiliates
|
5
|
18
|
|||||
Note
receivable – Resources Company
|
-
|
42
|
|||||
Materials
and supplies
|
65
|
85
|
|||||
Other
current assets
|
43
|
50
|
|||||
Total
current assets
|
214
|
318
|
|||||
Property
and Plant, Net
|
1,209
|
1,212
|
|||||
Investments
and Other Assets:
|
|||||||
Investments
in leveraged leases
|
-
|
21
|
|||||
Goodwill
|
575
|
575
|
|||||
Intangible
assets
|
58
|
62
|
|||||
Other
assets
|
19
|
35
|
|||||
Regulatory
assets
|
11
|
11
|
|||||
Total
investments and other assets
|
663
|
704
|
|||||
TOTAL
ASSETS
|
$
|
2,086
|
$
|
2,234
|
|||
LIABILITIES
AND STOCKHOLDER'S EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt
|
$
|
50
|
$
|
-
|
|||
Borrowings
from money pool
|
65
|
154
|
|||||
Intercompany
note payable – Ameren
|
156
|
186
|
|||||
Accounts
and wages payable
|
33
|
81
|
|||||
Accounts
and wages payable – affiliates
|
44
|
28
|
|||||
Other
current liabilities
|
51
|
55
|
|||||
Total
current liabilities
|
399
|
504
|
|||||
Long-term
Debt, Net
|
565
|
534
|
|||||
Preferred
Stock of Subsidiary Subject to Mandatory
Redemption
|
19
|
19
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
151
|
163
|
|||||
Accumulated
deferred investment tax credits
|
8
|
9
|
|||||
Regulatory
liabilities
|
46
|
41
|
|||||
Accrued
pension and other postretirement benefits
|
250
|
251
|
|||||
Other
deferred credits and liabilities
|
22
|
31
|
|||||
Total
deferred credits and other liabilities
|
477
|
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
|
1
|
-
|
|||||
Accumulated
other comprehensive income
|
8
|
23
|
|||||
Total
stockholder's equity
|
607
|
663
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDER'S EQUITY
|
$
|
2,086
|
$
|
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)
|
||||||
Six
Months Ended
|
||||||
June
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
9
|
$
|
11
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
50
|
51
|
||||
Deferred
income taxes and investment tax credits
|
(4
|
)
|
(13
|
)
|
||
Loss
on sale of leveraged lease investments
|
4
|
-
|
||||
Other
|
(1
|
) |
(3
|
)
|
||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
55
|
23
|
||||
Materials
and supplies
|
20
|
16
|
||||
Accounts
and wages payable
|
(26
|
)
|
(35
|
)
|
||
Taxes
accrued
|
(13
|
)
|
(4
|
)
|
||
Assets,
other
|
20
|
(1
|
)
|
|||
Liabilities,
other
|
(9
|
)
|
3
|
|||
Pension
and postretirement benefit obligations, net
|
1
|
7
|
||||
Net
cash provided by operating activities
|
106
|
55
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(42
|
)
|
(47
|
)
|
||
Proceeds
from note receivable - Resources Company
|
42
|
-
|
||||
Changes
in money pool advances
|
-
|
3
|
||||
Proceeds
from sale of leveraged leases
|
11
|
-
|
||||
Purchases
of emission allowances
|
(12 | ) | (21 | ) | ||
Sales
of emission allowances
|
1 | 1 | ||||
Net
cash provided by (used in) investing activities
|
-
|
(64
|
)
|
|||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(50
|
)
|
(30
|
)
|
||
Capital
issuance costs
|
(1
|
)
|
-
|
|||
Changes
in money pool borrowings
|
(89
|
)
|
(82
|
)
|
||
Proceeds
(repayment) - note payable - Ameren
|
(30
|
)
|
22
|
|||
Redemptions,
repurchases, and maturities:
|
||||||
Long-term
debt
|
(12
|
)
|
(6
|
)
|
||
Issuance
of long-term debt
|
96
|
-
|
||||
Capital
contribution from parent
|
-
|
101
|
||||
Net
cash provided by (used in) financing activities
|
(86
|
)
|
5
|
|||
Net
change in cash and cash equivalents
|
20
|
(4
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
3
|
7
|
||||
Cash
and cash equivalents at end of period
|
$
|
23
|
$
|
3
|
||
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
June
30,
|
Six
Months Ended
June
30,
|
||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
98
|
$
|
99
|
$
|
190
|
$
|
192
|
||||
Gas
|
48
|
46
|
198
|
171
|
||||||||
Total
operating revenues
|
146
|
145
|
388
|
363
|
||||||||
Operating
Expenses:
|
||||||||||||
Fuel
and purchased power
|
31
|
37
|
56
|
68
|
||||||||
Gas
purchased for resale
|
32
|
28
|
151
|
119
|
||||||||
Other
operations and maintenance
|
52
|
40
|
93
|
84
|
||||||||
Depreciation
and amortization
|
17
|
16
|
34
|
33
|
||||||||
Taxes
other than income taxes
|
4
|
4
|
13
|
10
|
||||||||
Total
operating expenses
|
136
|
125
|
347
|
314
|
||||||||
Operating
Income
|
10
|
20
|
41
|
49
|
||||||||
Other
Expenses:
|
||||||||||||
Miscellaneous
expense
|
(1
|
)
|
(2
|
)
|
(2
|
)
|
(3
|
)
|
||||
Total
other expenses
|
(1
|
)
|
(2
|
)
|
(2
|
)
|
(3
|
)
|
||||
Interest
Charges
|
4
|
3
|
8
|
7
|
||||||||
Income
Before Income Taxes
|
5
|
15
|
31
|
39
|
||||||||
Income
Taxes (Benefit)
|
(3
|
)
|
5
|
6
|
13
|
|||||||
Net
Income
|
8
|
10
|
25
|
26
|
||||||||
Preferred
Stock Dividends
|
1
|
-
|
1
|
1
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
7
|
$
|
10
|
$
|
24
|
$
|
25
|
||||
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)
|
||||||
June
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
22
|
$
|
2
|
||
Accounts
receivable – trade (less allowance for doubtful
|
||||||
accounts
of $6 and $5, respectively)
|
45
|
61
|
||||
Unbilled
revenue
|
34
|
59
|
||||
Accounts
receivable – affiliates
|
2
|
14
|
||||
Materials
and supplies
|
65
|
87
|
||||
Other
current assets
|
40
|
43
|
||||
Total
current assets
|
208
|
266
|
||||
Property
and Plant, Net
|
1,219
|
1,214
|
||||
Investments
in Leveraged Leases
|
-
|
21
|
||||
Intangible
Assets
|
7
|
4
|
||||
Other
Assets
|
25
|
41
|
||||
Regulatory
Assets
|
11
|
11
|
||||
TOTAL
ASSETS
|
$
|
1,470
|
$
|
1,557
|
||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt
|
$
|
50
|
$
|
-
|
||
Borrowings
from money pool
|
66
|
161
|
||||
Accounts
and wages payable
|
32
|
81
|
||||
Accounts
and wages payable – affiliates
|
43
|
26
|
||||
Other
current liabilities
|
44
|
48
|
||||
Total
current liabilities
|
235
|
316
|
||||
Long-term
Debt, Net
|
168
|
122
|
||||
Preferred
Stock Subject to Mandatory Redemption
|
19
|
19
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Accumulated
deferred income taxes, net
|
153
|
167
|
||||
Accumulated
deferred investment tax credits
|
8
|
8
|
||||
Regulatory
liabilities
|
195
|
187
|
||||
Accrued
pension and other postretirement benefits
|
150
|
146
|
||||
Other
deferred credits and liabilities
|
22
|
30
|
||||
Total
deferred credits and other liabilities
|
528
|
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
|
413
|
415
|
||||
Retained
earnings
|
93
|
119
|
||||
Accumulated
other comprehensive income (loss)
|
(5
|
)
|
9
|
|||
Total
stockholders' equity
|
520
|
562
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
|
1,470
|
$
|
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)
|
||||||
Six
Months Ended
|
||||||
June
30,
|
||||||
2006
|
2005
|
|||||
Cash
Flows From Operating Activities:
|
||||||
Net
income
|
$
|
25
|
$
|
26
|
||
Adjustments
to reconcile net income to net cash
|
||||||
provided
by operating activities:
|
||||||
Depreciation
and amortization
|
40
|
42
|
||||
Deferred
income taxes and investment tax credits
|
(3
|
)
|
(8
|
)
|
||
Loss
on sale of leveraged leases
|
6
|
-
|
||||
Other
|
(1
|
) |
3
|
|||
Changes
in assets and liabilities:
|
||||||
Receivables,
net
|
53
|
22
|
||||
Materials
and supplies
|
22
|
17
|
||||
Accounts
and wages payable
|
(26
|
)
|
(32
|
)
|
||
Taxes
accrued
|
(17
|
)
|
-
|
|||
Assets,
other
|
15
|
(1
|
)
|
|||
Liabilities,
other
|
(5
|
)
|
(5
|
)
|
||
Pension
and postretirement benefit obligations, net
|
4
|
13
|
||||
Net
cash provided by operating activities
|
113
|
77
|
||||
Cash
Flows From Investing Activities:
|
||||||
Capital
expenditures
|
(42
|
)
|
(47
|
)
|
||
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
|
(42
|
)
|
(67
|
)
|
||
Cash
Flows From Financing Activities:
|
||||||
Dividends
on common stock
|
(50
|
)
|
(20
|
)
|
||
Dividends
on preferred stock
|
(1
|
)
|
(1
|
)
|
||
Capital
issuance costs
|
(1
|
)
|
-
|
|||
Changes
in money pool borrowings
|
(95
|
)
|
(91
|
)
|
||
Issuance
of long-term debt
|
96
|
-
|
||||
Capital
contribution from parent
|
-
|
101
|
||||
Net
cash used in financing activities
|
(51
|
)
|
(11
|
)
|
||
Net
change in cash and cash equivalents
|
20
|
(1
|
)
|
|||
Cash
and cash equivalents at beginning of year
|
2
|
2
|
||||
Cash
and cash equivalents at end of period
|
$
|
22
|
$
|
1
|
||
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
June
30,
|
Six
Months Ended
June
30,
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
Revenues:
|
||||||||||||
Electric
|
$
|
271
|
$
|
268
|
$
|
513
|
$
|
503
|
||||
Gas
|
67
|
73
|
322
|
270
|
||||||||
Other
|
1
|
-
|
1
|
-
|
||||||||
Total
operating revenues
|
339
|
341
|
836
|
773
|
||||||||
Operating
Expenses:
|
||||||||||||
Purchased
power
|
171
|
165
|
348
|
322
|
||||||||
Gas
purchased for resale
|
36
|
44
|
237
|
190
|
||||||||
Other
operations and maintenance
|
61
|
60
|
120
|
102
|
||||||||
Depreciation
and amortization
|
18
|
19
|
37
|
40
|
||||||||
Taxes
other than income taxes
|
16
|
18
|
38
|
40
|
||||||||
Total
operating expenses
|
302
|
306
|
780
|
694
|
||||||||
Operating
Income
|
37
|
35
|
56
|
79
|
||||||||
Other
Income and Expenses:
|
||||||||||||
Miscellaneous
income
|
1
|
2
|
2
|
4
|
||||||||
Miscellaneous
expense
|
(1
|
)
|
(1
|
)
|
(2
|
)
|
(1
|
)
|
||||
Total
other income
|
-
|
1
|
-
|
3
|
||||||||
Interest
Charges
|
12
|
11
|
24
|
21
|
||||||||
Income
Before Income Taxes
|
25
|
25
|
32
|
61
|
||||||||
Income
Taxes
|
9
|
10
|
12
|
24
|
||||||||
Net
Income
|
16
|
15
|
20
|
37
|
||||||||
Preferred
Stock Dividends
|
-
|
-
|
1
|
1
|
||||||||
Net
Income Available to Common Stockholder
|
$
|
16
|
$
|
15
|
$
|
19
|
$
|
36
|
||||
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)
|
||||||
June
30,
|
December
31,
|
|||||
2006
|
2005
|
|||||
ASSETS
|
||||||
Current
Assets:
|
||||||
Cash
and cash equivalents
|
$
|
1
|
$
|
-
|
||
Accounts
receivable (less allowance for doubtful
|
||||||
accounts
of $8 and $8, respectively)
|
114
|
155
|
||||
Unbilled
revenue
|
85
|
118
|
||||
Accounts
receivable – affiliates
|
13
|
5
|
||||
Materials
and supplies
|
91
|
122
|
||||
Other
current assets
|
13
|
31
|
||||
Total
current assets
|
317
|
431
|
||||
Property
and Plant, Net
|
2,075
|
2,035
|
||||
Investments
and Other Assets:
|
||||||
Investment
in IP SPT
|
7
|
7
|
||||
Goodwill
|
326
|
326
|
||||
Other
assets
|
52
|
44
|
||||
Regulatory
assets
|
198
|
194
|
||||
Accumulated
deferred income taxes
|
-
|
19
|
||||
Total
investments and other assets
|
583
|
590
|
||||
TOTAL
ASSETS
|
$
|
2,975
|
$
|
3,056
|
||
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||
Current
Liabilities:
|
||||||
Current
maturities of long-term debt to IP SPT
|
$
|
64
|
$
|
72
|
||
Borrowings
from money pool
|
54
|
75
|
||||
Accounts
and wages payable
|
93
|
145
|
||||
Accounts
and wages payable – affiliates
|
18
|
29
|
||||
Taxes
accrued
|
-
|
15
|
||||
Other
current liabilities
|
105
|
135
|
||||
Total
current liabilities
|
334
|
471
|
||||
Long-term
Debt, Net
|
776
|
704
|
||||
Long-term
Debt to IP SPT
|
138
|
184
|
||||
Deferred
Credits and Other Liabilities:
|
||||||
Regulatory
liabilities
|
108
|
80
|
||||
Accrued
pension and other postretirement benefits
|
256
|
255
|
||||
Other
deferred credits and other noncurrent liabilities
|
57
|
75
|
||||
Total
deferred credits and other liabilities
|
421
|
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
|
1,196
|
1,196
|
||||
Preferred
stock not subject to mandatory redemption
|
46
|
46
|
||||
Retained
earnings
|
65
|
46
|
||||
Accumulated
other comprehensive loss
|
(1
|
)
|
(1
|
)
|
||
Total
stockholders’ equity
|
1,306
|
1,287
|
||||
TOTAL
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
2,975
|
$
|
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)
|
|||||||
Six
Months Ended
|
|||||||
June
30,
|
|||||||
2006
|
2005
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$
|
20
|
$
|
37
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
15
|
9
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
2
|
2
|
|||||
Deferred
income taxes
|
20
|
39
|
|||||
Changes
in assets and liabilities:
|
|||||||
Receivables,
net
|
66
|
40
|
|||||
Materials
and supplies
|
31
|
20
|
|||||
Accounts
and wages payable
|
(61
|
)
|
1
|
||||
Assets,
other
|
12
|
(19
|
)
|
||||
Liabilities,
other
|
(24
|
)
|
16
|
||||
Pension
and other postretirement benefit obligations, net
|
5
|
4
|
|||||
Net
cash provided by operating activities
|
86
|
149
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(83
|
)
|
(61
|
)
|
|||
Changes
in money pool advances
|
-
|
69
|
|||||
Net
cash provided by (used in) investing activities
|
(83
|
)
|
8
|
||||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
-
|
(40
|
)
|
||||
Dividends
on preferred stock
|
(1
|
)
|
(1
|
)
|
|||
Capital
issuance costs
|
(1
|
)
|
-
|
||||
Changes
in money pool borrowings, net
|
(21
|
)
|
-
|
||||
Redemptions
and repurchases of long-term debt
|
(46
|
)
|
(113
|
)
|
|||
Issuances
of long-term debt
|
75
|
-
|
|||||
Transitional
funding trust notes overfunding
|
(8
|
)
|
(3
|
)
|
|||
Net
cash used in financing activities
|
(2
|
)
|
(157
|
)
|
|||
Net
change in cash and cash equivalents
|
1
|
-
|
|||||
Cash
and cash equivalents at beginning of year
|
-
|
5
|
|||||
Cash
and cash equivalents at end of period
|
$
|
1
|
$
|
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)
June
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. EEI is a significant equity investment of UE, as determined
by SEC rules. The following table presents summarized financial information
of
EEI (in millions) for the three months and six months ended June 30, 2006 and
2005.
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Operating
revenues
|
$
|
88
|
$
|
42
|
$
|
184
|
$
|
84
|
||||
Operating
income
|
42
|
6
|
98
|
11
|
||||||||
Net
income
|
26
|
3
|
60
|
5
|
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 Statement 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.
Earnings
Per Share
There
were no material differences between Ameren’s basic and diluted earnings per
share amounts for the three months and six months ended June 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 replaces 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 June 30, 2006, and changes during the six-month period
ended June 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
on restricted shares
|
-
|
-
|
9,124
|
50.44
|
||||||||
Forfeitures
|
-
|
-
|
(2,436
|
)
|
47.58
|
|||||||
Vested(b)
|
(1,319
|
)
|
56.07
|
(213,198
|
)
|
43.38
|
||||||
Nonvested
at June 30, 2006
|
349,321
|
$
|
56.07
|
368,959
|
$
|
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 employee death 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 June 30, 2006 and 2005, respectively, and a related tax benefit of less
than $1 million and $2 million for the quarters ended June 30, 2006 and 2005,
respectively. Ameren recorded compensation expense of $5 million and $3 million
for each of the six month periods ended June 30, 2006 and 2005, respectively,
and a related
30
tax
benefit of less than $1 million and $2 million for the six month periods ended
June 30, 2006 and 2005, respectively. As of June 30, 2006, total compensation
cost of $24 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 six
month periods ended June 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.
Proposed
SFAS on Employer’s Accounting for Defined Benefit Pension and Other
Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and
132(R)
Issued
in
March 2006, this proposed SFAS would require employers to recognize the
overfunded or underfunded positions of defined benefit postretirement plans,
including pension plans, in their balance sheets. Existing unrecognized net
gains and losses and unrecognized prior-service costs and credits, as well
as
any new gains and losses and new prior-service costs and credits, would be
recognized as part of the balance sheet net pension asset or liability, with
a
corresponding credit or charge to OCI. Existing unrecognized net transition
assets or obligations would also be recognized as part of the balance sheet
pension and other postretirement benefit asset or liability, but the
corresponding adjustment upon adoption would be to retained earnings. If
approved, the standard would require Ameren to recognize additional pension
and
other postretirement benefit obligations of approximately $234 million and
$308
million, respectively, and write-off a $79 million pension-related intangible
asset, based on the funded status of Ameren’s defined benefit postretirement
plans as of December 31, 2005. Ameren would 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 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. If approved in its
current format, the provisions of this proposed SFAS would be applied
retroactively for the year ending December 31, 2006.
Revenue
Interchange
Revenues
The
following table presents the interchange revenues included in Operating Revenues
- Electric for the three months and six months ended June 30, 2006 and 2005.
See
Note 7 - Related Party Transactions for further information on affiliate
interchange revenues.
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren(a)
|
$
|
158
|
$
|
148
|
$
|
350
|
$
|
254
|
||||
UE
|
103
|
129
|
241
|
226
|
||||||||
CIPS
|
1
|
8
|
2
|
17
|
||||||||
Genco
|
41
|
67
|
90
|
109
|
||||||||
CILCORP
|
9
|
11
|
19
|
26
|
||||||||
CILCO
|
9
|
11
|
19
|
26
|
||||||||
IP
|
-
|
(b
|
)
|
-
|
(b
|
)
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations. Includes interchange revenues at Marketing
Company and EEI of $85 million and $174 million for the three months
and
six months ended June 30, 2006, respectively (2005 - $8 million and
$15
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 six months ended
June 30, 2006 and 2005. See Note 7 - Related Party Transactions for further
information on affiliate purchased power transactions.
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren(a)
|
$
|
277
|
$
|
244
|
$
|
550
|
$
|
442
|
||||
UE
|
68
|
66
|
135
|
104
|
||||||||
CIPS
|
113
|
105
|
230
|
191
|
||||||||
Genco
|
89
|
68
|
185
|
117
|
||||||||
CILCORP
|
6
|
13
|
8
|
22
|
||||||||
CILCO
|
6
|
13
|
8
|
22
|
||||||||
IP
|
171
|
165
|
348
|
322
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations. Includes purchased power for EEI of $2
million
and $3 million for the three months and six months ended June 30,
2006,
respectively (2005 - $1 million and $1 million, respectively).
|
31
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.
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 six months ended June 30, 2006 and 2005:
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren
|
$
|
39
|
$
|
41
|
$
|
85
|
$
|
81
|
||||
UE
|
27
|
28
|
52
|
50
|
||||||||
CIPS
|
3
|
2
|
9
|
7
|
||||||||
CILCORP
|
2
|
3
|
6
|
5
|
||||||||
CILCO
|
2
|
3
|
6
|
5
|
||||||||
IP
|
7
|
8
|
18
|
19
|
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:
· |
A
requested return on equity of 12%, and a rate base of $5.8 billion
with a
capital structure including about 52%
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.
|
· |
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% 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. The proposed rules implementing the fuel and
purchased power surcharge were filed with the Missouri Secretary of State in
June 2006. The public comment period on these rules ends on September 7, 2006.
Rules for the fuel and purchased power cost recovery mechanism are expected
to
be effective by December 31, 2006. 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
32
recovery
mechanisms in its electric rate case filed with
the MoPSC in July 2006.
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. 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.
See Note
7 - Related Party Transactions for a discussion of the affiliate power supply
agreements.
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
current 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 which
unanimously approved the Ameren Illinois utilities’ proposed power procurement
auction and the related tariffs, including the retail rates by which power
supply costs would be passed through to customers. The order includes 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.
|
· |
The
first auction is to take place in the first 10 days of September
2006.
|
· |
There
is a limitation of 35% on the amount of power any single supplier
can
provide the Ameren Illinois utilities’ expected annual load. Genco and
AERG, through Marketing Company, and UE will have the opportunity
to
participate in the power procurement auction for 2007, subject to
this
limit. Ameren-affiliated companies would be 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.
|
· |
Requires
an annual, postauction prudence review by the
ICC.
|
On
January 26, 2006, CIPS, CILCO and IP filed with the ICC a request for rehearing
with regard to the provision of the January 2006 order, which requires an
annual, postauction prudence review to be performed by the ICC. CIPS, CILCO
and
IP asserted in their request that there is no basis for such a prudence review.
In February 2006, the ICC denied this request for rehearing, and CIPS, CILCO
and
IP filed an appeal in the appellate court for the Fourth District in Illinois
on
February 9, 2006.
Certain
Illinois legislators, the Illinois attorney general, the Illinois governor
and
other parties have sought and continue to seek to block the power procurement
auction and/or the recovery of related costs for power supply resulting from
the
auction through rates to customers. In May 2005, the Illinois attorney general,
the CUB and the ELPC filed a motion to dismiss the Ameren Illinois utilities’
proposed power procurement auction with the ICC on the basis 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. This motion and a subsequent appeal were denied by the
administrative law judge in the case and by the ICC, respectively.
In
September 2005, Illinois Governor Rod Blagojevich sent a letter to the ICC
expressing his opposition to CIPS’, CILCO’s and IP’s proposed power procurement
auction process and requesting dismissal of the pending proceeding for approval
of such process. CIPS, CILCO and IP responded to the governor's letter citing
legal deficiencies in his position and the potential adverse consequences that
could result if his position is ultimately sustained. Copies of the governor’s
letter and the Ameren Illinois utilities’ response letter appear as Exhibits
99.1 and 99.2, respectively, to the Current Report on Form 8-K dated September
15, 2005. Also in September 2005, the Illinois attorney general, the Cook County
state’s attorney, the CUB and the ELPC filed a complaint in the Circuit Court of
Cook County, Illinois, against the ICC and the individual ICC commissioners
making claims similar to those included in their motion to dismiss that was
denied. The complaint asked the court to determine that the ICC lacks authority
to approve the auction proposal. It sought injunctive relief prohibiting the
ICC
from approving the proposals by CIPS, CILCO and IP. On January 20, 2006, the
Circuit Court of Cook County, Illinois, entered an order dismissing the
complaint with prejudice.
Both
the
Illinois governor's letter and the attorney general's lawsuit discussed in
the
previous paragraph assert that the energy component of CIPS’, CILCO’s and IP’s
retail rates for electricity should not be based on the costs to
33
procure
energy and capacity in the wholesale market.
Although CIPS, CILCO and IP have received favorable rulings from the ICC and
the
Circuit Court of Cook County with respect to their proposals, we anticipate
that
certain Illinois legislators,
the Illinois attorney general, the Illinois governor, and others will persist
in
their efforts to block the power procurement auction and the recovery of related
costs through rates to customers. In February 2006, the Illinois attorney
general, CUB and ELPC filed with the ICC requests for a rehearing of the ICC’s
January 24, 2006, order approving the Ameren Illinois utilities power
procurement auction and related tariffs. Their arguments for a rehearing were
generally similar to those that they previously raised as discussed above.
In
March 2006, the ICC denied these requests for rehearing. In March and April
2006, these parties filed appeals in the appellate court for the First District
in Illinois. 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. The matter is still pending. We
are
unable to predict whether such efforts will ultimately be successful. 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 could result in material adverse consequences to Ameren and the
Ameren Illinois utilities. As noted in their response letter to the Illinois
governor, these consequences could include a significant drop in credit ratings
(possibly to below investment-grade status), a loss of access to the capital
markets, higher borrowing costs, higher power supply costs, an inability to
make
timely energy infrastructure investments, impaired customer service, job losses,
and financial insolvency.
With
regard to the delivery service component of customer rates, 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).
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 April 2006, the Illinois attorney general
recommended increases in revenues for electric delivery services aggregating
$71
million for the Ameren Illinois utilities (CIPS - $7 million decrease, CILCO
-
$19 million increase and IP - $59 million increase). In subsequent testimony,
the Illinois attorney general accepted certain of the Ameren Illinois utilities’
positions increasing the estimated aggregate recommended revenue increase
to $100 million. Other parties also made recommendations in the case. The ICC
has until November 2006 to render a decision in these rate cases.
The
Illinois legislature held hearings in 2005 and 2006 regarding the framework
for
retail rate determination and power procurement. In February 2006, legislation
was introduced in the Illinois House of Representatives that would extend the
electric rate freeze in Illinois through 2010. 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 potential significant increases in customer rates for the Ameren Illinois
utilities beginning in 2007. We 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 solid investment-grade credit ratings for CIPS, CILCO and IP.
We
believe a rate increase phase-in plan, providing for deferral of costs with
certainty of full and timely recovery of any deferred costs, would require
legislation in Illinois. In March 2006, legislation was introduced in the
Illinois House of Representatives that would allow the 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. Securitization would allow these special purpose vehicles to
issue debt securities and use the proceeds to pay the utilities immediately
upon
issuance of the bonds for the deferred power costs for which the utilities
did
not receive reimbursement from customers during a phase-in deferral
period. Customers would fund, through dedicated charges included on their
electric bills, a future payment stream that would be used to service the
securitized debt. In effect, through these dedicated charges utility
customers would pay in the future for power used, but not paid for, during
a
phase-in deferral period. This approach has the effect of spreading over
the life of the bonds, a period of up to 10 years, the potentially significant
initial electric rate increase for residential customers that would otherwise
be
necessary to pay the power procurement costs on a current basis. If passed,
this
legislation would assist our Ameren Illinois utilities in maintaining their
financial integrity while allowing them to
34
recover
costs from customers over a longer term. We cannot predict what actions, if
any, the Illinois legislature may ultimately take. In June 2006, the Ameren
Illinois utilities filed with the ICC a rate increase phase-in and revenue
securitization
plan for residential customers similar to the proposed legislation outlined
above that would relate to the deferral of power and supply costs for 2007
and
2008. Legislation would be needed for this plan to become effective. In July
2006, the Illinois attorney general filed a motion with the ICC to dismiss
this
plan. The Ameren Illinois utilities responded in July 2006 and the matter is
currently pending before the ICC. Any decision or action that impairs CIPS’,
CILCO’s and IP’s ability to fully recover purchased power costs from their
electric customers in a timely manner could result in material adverse
consequences for these companies and for Ameren.
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.
There can be no assurance that Ameren and the Ameren Illinois utilities 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 and the
Ameren Illinois utilities 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 in 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 $5 million and $14 million transfer of electric
margins from Genco to UE during the three months and six months ended June
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 will require acceptance by the FERC, a
request for which was filed on August 1, 2006.
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 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
35
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 its interests in its remaining four leveraged lease assets.
NOTE
3 - SHORT-TERM BORROWINGS AND LIQUIDITY
Short-term
borrowings typically consist of 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 June 30, 2006 and December 31, 2005,
respectively:
Ameren
|
UE
|
||||||
June
30, 2006:
|
|||||||
Average
daily borrowings outstanding during 2006
|
$
|
272
|
$
|
258
|
|||
Weighted-average
interest rate during 2006
|
4.87
|
%
|
4.88
|
%
|
|||
Peak
short-term borrowings during 2006
|
$
|
586
|
$
|
470
|
|||
Peak
interest rate during 2006
|
5.50
|
%
|
5.50
|
%
|
|||
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
June
30, 2006, Ameren had $1.5 billion of committed credit facilities, consisting
of
two facilities each maturing in July 2010, in the amounts of $1.15 billion
and
$350 million. The entire amount of the $1.15 billion facility was available
to
Ameren; UE could directly borrow under this facility up to $500 million on
a
364-day basis; and CIPS, Genco, CILCO, and IP could also each directly borrow
under this facility up to $150 million, also 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 initial 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
have borrowing authority under this facility effective July 13, 2006, but
temporarily remain parties to the agreement 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
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
36
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. The ability of CIPS,
CILCO and IP to borrow under this facility is subject to the receipt of
necessary regulatory approvals, which are expected to be received in the third
quarter of 2006, and the issuance by CIPS, CILCO and IP of mortgage bonds as
security as described below. These companies will continue to have access to
short-term funding via Ameren’s utility money pool and other intercompany
borrowing arrangements. Once CIPS, CILCO and IP are able to borrow under this
new facility, they will be removed as parties to the $1.15 billion credit
facility.
The
obligations of each borrower under the new 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. 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.
Subject
to the receipt of regulatory approval, the obligations of CIPS, CILCO and IP
under the new facility will be secured by the issuance of mortgage bonds by
each
such utility under its respective mortgage indenture. 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 generating stations 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 June 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 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 can access the committed credit
facility at Ameren. The availability of funds is 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 six months ended June 30, 2006, was 5.0% and 4.7%, respectively (2005 -
3.0%
and 2.7%, respectively).
Non-state-regulated
Ameren subsidiaries, including Genco and AERG, have the ability to access
funding from Ameren’s credit facilities 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 six months ended June 30, 2006, was 4.6%
and
4.5%, respectively (2005 - 5.5% and 6.9%, 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 six months ended June 30, 2006 and 2005.
37
Indebtedness
Provisions and Other Covenants
Ameren’s
bank credit facilities 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. Once CIPS, CILCO
and
IP are no longer parties to this agreement, which occurs when they obtain the
ability to borrow under their new facility as discussed above, they will no
longer be considered subsidiaries for purposes of the cross default provisions.
This is expected to occur in the third quarter of 2006.
Under
the
amended $1.15 billion credit facility, (i) restrictions apply limiting
investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their
subsidiaries by Ameren and certain subsidiaries and (ii) 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. These
restrictions, as well as the capitalization financial covenant, will continue
to
apply to CIPS, CILCO and IP until such time as each ceases to be subject to
the
covenants of the amended facility. CIPS, CILCO and IP will continue to be
subject to the covenants of the amended facility until such time as the
conditions to their borrowing under the new $500 million credit facility are
satisfied and they have provided notice of termination of their status under
the
amended facility, both of which are expected to occur in the third quarter
of
2006.
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, subject
to exceptions, 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 may not make any dividend or
distribution on any shares of its capital stock while such below
investment-grade credit rating is in effect. 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. Notwithstanding the two prior sentences, each borrower
may make dividends or distributions on shares of its capital stock during any
fiscal year of such borrower not to exceed $10 million. 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 dividend payment
limitation. The other borrowers are not currently limited in their dividend
payments by this provision of the new 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
June 30, 2006, the ratio of total indebtedness to total capitalization
(calculated in accordance with the provisions of the credit facilities in effect
at that time) for Ameren, UE, CIPS, Genco, CILCO, and IP was 50%, 51%, 47%,
56%,
36% and 44%, respectively.
None
of
Ameren’s revolving credit facilities or financing arrangements contain credit
rating triggers. At June 30, 2006, the Ameren Companies were in compliance
with
their credit facility provisions and covenants.
38
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 0.6 million new shares of common stock valued
at
$30 million and 1.1 million new shares valued at $57 million in the three
months
and six months ended June 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.
CILCORP
In
March
2006, CILCORP repurchased $2 million in principal amount of its 9.375% senior
notes 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 $3 million (2005 - $4 million) for the three
months and six months ended June 30, 2006, respectively, and was included in
interest expense in the Consolidated Statements of Income of Ameren and
CILCORP.
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.
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%
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 in July 2006 to redeem CILCO’s $20 million 7.73% secured
medium-term notes due 2025 and to reduce short-term money pool
borrowings.
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.
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 - $4 million) and $7 million (2005 - $9 million) for the three months
and
six months ended June 30, 2006, respectively, and was included in interest
expense in the Consolidated Statements of Income of Ameren and IP.
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 June 30, 2006,
at an assumed interest and dividend rate of 7%.
39
Required
Interest Coverage Ratio(a)
|
Actual
Interest Coverage Ratio
|
Bonds
Issuable(b)(c)
|
Required
Dividend Coverage Ratio(d)
|
Actual
Dividend Coverage Ratio
|
Preferred
Stock Issuable
|
|||||||||||||
UE
|
2.0
|
4.4
|
$
|
2,217
|
2.5
|
44.5
|
$
|
1,426
|
||||||||||
CIPS
|
2.0(e)
|
|
3.8
|
191
|
1.5
|
2.2
|
215
|
|||||||||||
CILCO
|
2.0(e)(f)
|
|
9.0
|
355
|
2.5
|
12.5
|
113(g)
|
|
||||||||||
IP
|
2.0
|
5.6
|
645(h)
|
|
1.5
|
2.7
|
521
|
(a)
Coverage
required on the annual interest charges on first mortgage bonds outstanding
and
to be issued.
(b)
Amount
of
bonds issuable based on meeting required coverage ratios.
(c)
See
Note
3 - Short-term Borrowings and Liquidity for a discussion regarding restrictions
on the issuance of bonds by CIPS, CILCO and IP under the $500 million credit
facility entered
into by these companies.
(d) 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.
(e)
Coverage
is not required in certain cases when additional first mortgage bonds are
issued
on the basis of retired bonds.
(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 six months ended June
30,
2006, CILCO had earnings equivalent to at least 35% of the principal amount
of
all mortgage
bonds outstanding.
(g)
See
Note
3 - Short-term Borrowings and Liquidity for a discussion regarding a restriction
on the issuance of preferred stock by CILCO under the $500 million credit
facility.
(h) In
addition to the coverage test based on property additions, IP has the ability
to
issue bonds based upon retired bond capacity, for which no earnings coverage
test is required.
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
$1.7 billion of free and unrestricted retained earnings at June 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. If, however, 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 June 30, 2006,
$33,000
of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds are
callable at the end of 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 June 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)
|
5.1
|
≤60%
|
55%
|
CILCORP(c)
|
≥2.2
|
2.4
|
≤67%
|
39%
|
(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
June
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.
40
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 six months ended June 30, 2006 and
2005:
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren:(a)
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
1
|
$
|
1
|
$
|
3
|
$
|
2
|
||||
Allowance
for equity funds used during construction
|
-
|
3
|
1
|
7
|
||||||||
Other
|
3
|
2
|
4
|
4
|
||||||||
Total
miscellaneous income
|
$
|
4
|
$
|
6
|
$
|
8
|
$
|
13
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(1
|
)
|
$
|
(6
|
)
|
$
|
(1
|
)
|
$
|
(7
|
)
|
Total
miscellaneous expense
|
$
|
(1
|
)
|
$
|
(6
|
)
|
$
|
(1
|
)
|
$
|
(7
|
)
|
UE:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
1
|
$
|
-
|
$
|
2
|
$
|
-
|
||||
Allowance
for equity funds used during construction
|
-
|
1
|
1
|
6
|
||||||||
Other
|
-
|
1
|
1
|
3
|
||||||||
Total
miscellaneous income
|
$
|
1
|
$
|
2
|
$
|
4
|
$
|
9
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(4
|
)
|
Total
miscellaneous expense
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(4
|
)
|
CIPS:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
4
|
$
|
4
|
$
|
8
|
$
|
9
|
||||
Other
|
-
|
-
|
1
|
-
|
||||||||
Total
miscellaneous income
|
$
|
4
|
$
|
4
|
$
|
9
|
$
|
9
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
-
|
$
|
(4
|
)
|
$
|
(1
|
)
|
$
|
(4
|
)
|
|
Total
miscellaneous expense
|
$
|
-
|
$
|
(4
|
)
|
$
|
(1
|
)
|
$
|
(4
|
)
|
|
Genco:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Other
|
$
|
-
|
$
|
1
|
$
|
-
|
$
|
1
|
||||
Total
miscellaneous income
|
$
|
-
|
$
|
1
|
$
|
-
|
$
|
1
|
||||
CILCORP:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
1
|
$
|
-
|
$
|
1
|
$
|
-
|
||||
Total
miscellaneous income
|
$
|
1
|
$
|
-
|
$
|
1
|
$
|
-
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(1
|
)
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
(5
|
)
|
Total
miscellaneous expense
|
$
|
(1
|
)
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
(5
|
)
|
CILCO:
|
||||||||||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(1
|
)
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(3
|
)
|
Total
miscellaneous expense
|
$
|
(1
|
)
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(3
|
)
|
IP:
|
||||||||||||
Miscellaneous
income:
|
||||||||||||
Interest
and dividend income
|
$
|
1
|
$
|
1
|
$
|
1
|
$
|
2
|
||||
Allowance
for equity funds used during construction
|
-
|
1
|
-
|
1
|
||||||||
Other
|
-
|
-
|
1
|
1
|
||||||||
Total
miscellaneous income
|
$
|
1
|
$
|
2
|
$
|
2
|
$
|
4
|
||||
Miscellaneous
expense:
|
||||||||||||
Other
|
$
|
(1
|
)
|
$
|
(1
|
)
|
$
|
(2
|
)
|
$
|
(1
|
)
|
Total
miscellaneous expense
|
$
|
(1
|
)
|
$
|
(1
|
)
|
$
|
(2
|
)
|
$
|
(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
41
transactions
going to delivery or settlement, resulting in a $2 million gain for Ameren
for
the three months ended June 30, 2006 (2005 - $1 million gain for Ameren) and
a
$1 million loss for Ameren, a $1 million loss for Genco and a $2 million loss
for IP for the six months ended June 30, 2006 (2005 - $3 million gain for
Ameren, $1 million gain for Genco).
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 June 30, 2006:
Ameren(a)
|
UE
|
CIPS
|
Genco
|
CILCORP/
CILCO
|
IP
|
|||||||||||||
Derivative
instruments carrying value:
|
||||||||||||||||||
Total
assets
|
$
|
59
|
$
|
4
|
$
|
4
|
$
|
1
|
$
|
18
|
$
|
4
|
||||||
Total
deferred credits and liabilities
|
16
|
6
|
-
|
-
|
-
|
2
|
||||||||||||
Gains
(losses) deferred in Accumulated OCI:
|
||||||||||||||||||
Power
forwards and swaps(b)
|
23
|
1
|
-
|
1
|
-
|
(2
|
)
|
|||||||||||
Interest
rate swaps(c)
|
4
|
-
|
-
|
4
|
-
|
-
|
||||||||||||
Gas
swaps and futures contracts(d)
|
22
|
2
|
4
|
-
|
17
|
-
|
(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.
|
(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
2008.
|
Other
Derivatives
The
following table presents the net change in market value for the three months
and
six months ended June 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
|
Six
Months
|
|||||||||||
Gains
(Losses)
|
2006
|
2005
|
2006
|
2005
|
||||||||
SO2
options and swaps:
|
||||||||||||
Ameren
|
$
|
(2
|
)
|
$
|
-
|
$
|
(3
|
)
|
$
|
(6
|
)
|
|
UE
|
(1
|
)
|
-
|
2
|
(1
|
)
|
||||||
Genco
|
(1
|
)
|
-
|
(4
|
)
|
(5
|
)
|
|||||
CILCO/CILCORP
|
-
|
-
|
(1
|
)
|
-
|
|||||||
Coal
Options:
|
||||||||||||
Ameren
|
(1
|
)
|
-
|
(1
|
)
|
-
|
||||||
UE
|
(1
|
)
|
-
|
(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 six months ended
June
30, 2006 and 2005:
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Genco
sales to
Marketing
Company
|
5,296
|
5,196
|
10,887
|
10,096
|
||||||||
Marketing
Company
sales
to CIPS
|
2,997
|
2,497
|
6,076
|
4,553
|
||||||||
EEI
sales to UE
|
-
|
744
|
-
|
1,441
|
||||||||
EEI
sales to CIPS
|
-
|
371
|
-
|
943
|
||||||||
EEI
sales to IP
|
-
|
381
|
-
|
794
|
The
EEI
agreement that 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.
Joint
Dispatch Agreement
UE
and
Genco jointly dispatch electric generation under the JDA among UE, CIPS and
Genco. UE and Genco have
42
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 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, pending acceptance by FERC.
The
following table presents the amount of gigawatthour sales under the JDA for
the
three months and six months ended June 30, 2006 and 2005:
Three
Months
|
Six
Months
|
|||
2006
|
2005
|
2006
|
2005
|
|
UE
sales to Genco
|
2,639
|
3,814
|
5,434
|
6,763
|
Genco
sales to UE
|
1,111
|
1,219
|
1,717
|
1,816
|
The
following table presents the short-term power sales margins under the JDA for
UE
and Genco for the three months and six months ended June 30, 2006 and
2005:
Three
Months
|
Six
Months
|
|||
2006
|
2005
|
2006
|
2005
|
|
UE
|
$
25
|
$
43
|
$
58
|
$
79
|
Genco
|
5
|
27
|
17
|
47
|
Total
|
$
30
|
$
70
|
$
75
|
$
126
|
Money
Pools
See
Note
3 - Short-term Borrowings 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 $7 million (2005 - $8
million) for the three months and six months ended June 30, 2006 and
2005.
In
June
2006, CIPS repaid in full its May 2005 $67 million subordinated promissory
note
to UE. UE and CIPS recorded interest income and expense, respectively, of less
than $1 million (2005 - less than $1 million) and $1 million (2005 - less than
$1 million) for the three months and six months ended June 30, 2006,
respectively, related to this note.
The
average interest rate on CILCORP’s note payable to Ameren was 4.6% and 4.3% for
the three months and six months ended June 30, 2006, respectively (2005 - 5.5%
and 6.9%, respectively). CILCORP recorded interest expense of $2 million (2005
-
$1 million) and $4 million (2005 - $3 million) for the three months and six
months ended June 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 six months ended June
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 in Note 3 -
Short-term Borrowings and Liquidity.
Three
Months
|
Six
Months
|
||||||||||||||||||||||||||||||||
Agreement
|
UE
|
CIPS
|
Genco
|
CILCORP(a)
|
IP
|
UE
|
CIPS
|
Genco
|
CILCORP(a)
|
IP
|
|||||||||||||||||||||||
Operating
Revenues:
|
|||||||||||||||||||||||||||||||||
Power
supply agreement
|
2006
|
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
194
|
|
$
|
1
|
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
389
|
|
$
|
5
|
|
$
|
(b
|
)
|
|
with
Marketing Company
|
2005
|
(b
|
)
|
8
|
195
|
6
|
(b
|
)
|
(b
|
)
|
17
|
374
|
21
|
(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
|
49
|
(b
|
)
|
27
|
(b
|
)
|
(b
|
)
|
121
|
(b
|
)
|
46
|
(b
|
)
|
(b
|
)
|
||||||||||||||||
2005
|
|
|
56
|
|
|
(b
|
)
|
|
21
|
|
|
(b
|
)
|
|
(b
|
)
|
|
97
|
|
|
(b
|
)
|
|
31
|
|
|
(b
|
)
|
|
(b
|
)
|
||
Total
Operating
|
2006
|
$
|
49
|
$
|
(b
|
)
|
$
|
221
|
$
|
1
|
$
|
(b
|
)
|
$
|
121
|
$
|
(b
|
)
|
$
|
435
|
$
|
5
|
$
|
(b
|
)
|
||||||||
Revenues
|
2005
|
56
|
8
|
216
|
6
|
(b
|
)
|
97
|
17
|
405
|
21
|
(b
|
)
|
43
|
Three
Months
|
Six
Months
|
||||||||||||||||||||||||||||||||
Agreement
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
||||||||||||||||||||||||
Fuel
and Purchased Power:
|
||||||||||||||||||||||||||||||||||
JDA
|
2006
|
$
|
27
|
$
|
(b
|
)
|
$
|
49
|
$
|
(b
|
)
|
$
|
(b
|
)
|
$
|
46
|
$
|
(b
|
)
|
$
|
121
|
$
|
(b
|
)
|
$
|
(b
|
)
|
|||||||
2005
|
21
|
(b
|
)
|
56
|
(b
|
)
|
(b
|
)
|
31
|
(b
|
)
|
97
|
(b
|
)
|
(b
|
)
|
||||||||||||||||||
Power
supply agreement
|
|
2006
|
(b
|
)
|
111
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
219
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
||||||||||||||
with
Marketing Company
|
2005
|
2
|
94
|
(c
|
)
|
4
|
(b
|
)
|
4
|
170
|
2
|
7
|
(b
|
)
|
||||||||||||||||||||
Power
supply agreement with EEI
|
2005
|
16
|
8
|
(b
|
)
|
(b
|
)
|
13
|
30
|
17
|
(b
|
)
|
(b
|
)
|
27
|
|||||||||||||||||||
Executory
tolling agreement with
|
2006
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
7
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
20
|
(b
|
)
|
|||||||||||||||
Medina
Valley
|
2005
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
8
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
(b
|
)
|
18
|
(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
|
$
|
27
|
$
|
111
|
$
|
49
|
$
|
7
|
$
|
(b
|
)
|
$
|
46
|
$
|
219
|
$
|
121
|
$
|
20
|
$
|
(b
|
)
|
|||||||||||
Purchased
Power
|
2005
|
39
|
102
|
56
|
12
|
13
|
65
|
187
|
99
|
25
|
27
|
|||||||||||||||||||||||
Other
Operating Expenses:
|
||||||||||||||||||||||||||||||||||
Ameren
Services support
|
2006
|
$
|
36
|
$
|
13
|
$
|
6
|
$
|
13
|
$
|
19
|
$
|
69
|
$
|
24
|
$
|
11
|
$
|
25
|
$
|
36
|
|||||||||||||
services
agreement
|
2005
|
40
|
11
|
5
|
9
|
22
|
81
|
22
|
10
|
21
|
22
|
|||||||||||||||||||||||
Ameren
Energy support
|
2006
|
2
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
4
|
(b
|
)
|
1
|
(b
|
)
|
(b
|
)
|
||||||||||||||||
services
agreement
|
2005
|
1
|
(b
|
)
|
(c
|
)
|
(b
|
)
|
(b
|
)
|
2
|
(b
|
)
|
1
|
(b
|
)
|
(b
|
)
|
||||||||||||||||
AFS
support services
|
2006
|
1
|
1
|
(c
|
)
|
1
|
(c
|
)
|
2
|
1
|
1
|
1
|
1
|
|||||||||||||||||||||
agreement
|
2005
|
1
|
1
|
(c
|
)
|
(c
|
)
|
1
|
2
|
1
|
1
|
1
|
1
|
|||||||||||||||||||||
Total
Other
|
2006
|
$
|
39
|
$
|
14
|
$
|
6
|
$
|
14
|
$
|
19
|
$
|
75
|
$
|
25
|
$
|
13
|
$
|
26
|
$
|
37
|
|||||||||||||
Operating
Expenses
|
2005
|
42
|
12
|
5
|
9
|
23
|
85
|
23
|
12
|
22
|
23
|
|||||||||||||||||||||||
Interest
Income (Expense):
|
||||||||||||||||||||||||||||||||||
Money
pool borrowings
|
2006
|
$
|
(c
|
)
|
$
|
(1
|
)
|
$
|
3
|
$
|
1
|
$
|
(c
|
)
|
$
|
(c
|
)
|
$
|
(1
|
)
|
$
|
5
|
$
|
3
|
$
|
1
|
||||||||
(advances)
|
2005
|
2
|
(c
|
)
|
1
|
1
|
(1
|
)
|
2
|
(c
|
)
|
3
|
2
|
(2
|
)
|
(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.
44
Callaway Nuclear Plant
The
following table presents insurance coverage at UE’s Callaway nuclear plant at
June 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)
|
|
$
|
21
|
|
Replacement
power:
|
||||||
Nuclear
Electric Insurance Ltd.
|
$
|
490(e)
|
|
$
|
7
|
(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.
|
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 our 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
June 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 June 30, 2006:
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter(a)
|
|||||||||||||
Ameren(b)
|
$
|
609
|
$
|
498
|
$
|
507
|
$
|
404
|
$
|
238
|
$
|
77
|
||||||
UE
|
344
|
289
|
251
|
213
|
159
|
77
|
||||||||||||
Genco
|
129
|
100
|
154
|
136
|
42
|
-
|
||||||||||||
CILCORP/CILCO
|
61
|
36
|
35
|
27
|
18
|
-
|
(a) |
Commitments
for coal are until 2011.
|
(b) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
As
of
June 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 June 30, 2006:
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter(a)
|
|||||||||||||
Ameren(b)
|
$
|
373
|
$
|
580
|
$
|
407
|
$
|
237
|
$
|
148
|
$
|
249
|
||||||
UE
|
57
|
65
|
60
|
39
|
26
|
74
|
||||||||||||
CIPS
|
62
|
119
|
87
|
58
|
40
|
105
|
||||||||||||
Genco
|
11
|
24
|
20
|
8
|
8
|
10
|
||||||||||||
CILCORP/CILCO
|
89
|
147
|
107
|
60
|
32
|
33
|
||||||||||||
IP
|
141
|
213
|
131
|
71
|
41
|
25
|
(a) |
Commitments
for natural gas are until 2016.
|
(b) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
45
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
by
September and November 2006, respectively. 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
subjected to public review and comment. We do not expect the state regulations
to be finalized until late 2006. The Illinois EPA proposed rules for mercury
significantly stricter than the federal rules. An implementation plan from
Missouri regulators is still under review and consideration and could result
in
significantly higher costs than estimated for UE below. 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) a proposed agreement between Genco, CILCO, EEI, and the
Illinois EPA on a multi-pollutant strategy for NOx,
SO2,
mercury
and fine particulates. This agreement, which was entered into in July 2006
and
is subject to approval by the Illinois Pollution Control Board, addresses the
Illinois EPA's proposed stricter rules for mercury and will result in a
significant amount of additional NOx,
SO2
and
mercury control equipment being installed to reduce these emissions. 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
state
of Missouri must also develop a plan to meet the new 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 alternative plan to comply with this standard, the cost impact could
be material to UE. At this time, we are unable to determine the impact such
a
state action 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
46
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 June 30, 2006.
SO2 (a)
|
NOx (b)
|
Book
Value
|
|||||||
UE
|
1,850,000
|
387
|
$
|
63
|
|||||
Genco
|
690,000
|
10,334
|
89
|
||||||
CILCO
|
330,000
|
1,206
|
58
|
||||||
EEI
|
360,000
|
1,935
|
40
|
(a) |
Vintages
are from 2006 to 2016. Each company possesses additional allowances
for
use in periods beyond 2016.
|
(b) |
Vintages
are from 2006 to 2008.
|
The
Illinois EPA has not yet issued any NOx
emission
allowance allocations for 2007 and 2008. UE, Genco, CILCO and EEI expect to
use
a substantial portion of the SO2
and
NOx
allowances for ongoing operations. Allocations of NOx
allowances for Missouri generating facilities will be 10,178 tons per season
in
2007 and 2008. 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. This information request is being complied
with, but we cannot predict the outcome of this matter.
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
June 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 June 30, 2006, CIPS, CILCO and IP had recorded liabilities of $26
million, $3 million and $66 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 recently enacted law in Missouri 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 June 30, 2006, UE had recorded $10 million
to represent its estimated minimum obligation for MGP sites. UE also is
47
responsible
for four electric sites in Missouri that
have corporate cleanup liability, most as a result of federal agency
mandates.
As of June 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 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 June 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. The incident is being investigated
by FERC and state authorities. UE expects the results of these reviews later
in
2006. Preliminary 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.
In
late
May 2006,
the FERC
released a report by an Independent Panel of Consultants on the technical
reasons for the December breach. The report cited the primary cause of the
Taum Sauk breach as overtopping of the upper reservoir dam due to improperly
maintained and installed water level monitors. The report stated that the
monitors became loose and indicated reservoir levels lower than actual
levels. In addition, the panel found emergency backup sensors proved
ineffective because they were set at an elevation above the lowest points
along
the parapet wall on the top of the reservoir. As a result, the sensors
failed their protection role because their location enabled the overtopping
to
occur before the probes could trigger a shutdown. The report stated that
another
factor contributing to the overtopping was that UE typically operated with
high
water levels of one foot below the top of the parapet wall, which was not
enough
to take into account possible mistakes in project operation. A secondary
cause, the report said, was the marginally stable dumped
48
“dirty”
(silt, sands and gravels) rockfill embankment and associated parapet
wall.
The
facility will remain out of service until reviews by FERC and 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 most, if not all, of 2008.
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 will be covered by insurance. UE expects the total cost for damage
and
liabilities resulting from the Taum Sauk incident to range from $63 million
to
$83 million. As of June 30, 2006, UE had paid $27 million and accrued a $36
million liability, while expensing $11 million and recording a $52 million
receivable due 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 or federal authorities. Until the reviews conducted by
state
and federal 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 129 parties are named in some pending cases and as
few
as six in others. However, in the cases that were pending as of June 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.
From
April 1, 2006, through June 30, 2006, seven additional asbestos-related lawsuits
were filed against Ameren, UE, CIPS, CILCO and IP, mostly in the Circuit
Court
of Madison County, Illinois. Three lawsuits were dismissed and two were settled.
The following table presents the status as of June 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
|
310
|
31
|
166
|
125
|
2
|
36
|
144
|
||||||||||||||
Settled
|
95
|
-
|
48
|
39
|
-
|
10
|
48
|
||||||||||||||
Dismissed
|
143
|
22
|
92
|
46
|
2
|
6
|
63
|
||||||||||||||
Pending
|
72
|
9
|
26
|
40
|
-
|
20
|
33
|
(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
June 30, 2006, six 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
recovered 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.
49
Retiree
Medical Plan Litigation
In
June
2003, 20 retirees and surviving spouses of retirees of various Ameren companies
(the plaintiffs) filed a complaint in the U.S. District Court, Southern District
of Illinois, against Ameren, UE, CIPS, Genco and Ameren Services, and against
our Retiree Medical Plan, and by an amended complaint, against our Group
Medical
Plan (the defendants). The retirees were members of various local labor unions
of the IBEW and the IUOE. The complaint, referred to as Barnett et al., vs.
Ameren Corporation, et al., alleged, among other things, that the defendants’
recent actions requiring retirees to pay a portion of their own health care
premiums or increasing the premiums paid by dependents or surviving spouses
of
retirees violate ERISA and the Labor Management Relations Act of 1947 and
constitute a breach of the defendants’ fiduciary duties. In February 2006, the
U.S. Seventh Circuit Court of Appeals affirmed a district court’s granting of
summary judgment in favor of the defendants. This decision is final and not
subject to further appeal.
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 2015. 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. 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.
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 six months ended June 30, 2006 and 2005, is shown
below
for the Ameren Companies:
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Ameren:(a)
|
||||||||||||
Net
income
|
$
|
123
|
$
|
185
|
$
|
193
|
$
|
306
|
||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$7,
$4, $(2) and $10, respectively
|
11
|
1
|
(4
|
)
|
18
|
|||||||
Reclassification
adjustments for (gains) included in net income, net of taxes
of
$2, $1, $5 and $1, respectively
|
(3
|
)
|
(2
|
)
|
(8
|
)
|
(2
|
)
|
||||
Total
comprehensive income, net of taxes
|
$
|
131
|
$
|
184
|
$
|
181
|
$
|
322
|
||||
UE:
|
||||||||||||
Net
income
|
$
|
92
|
$
|
132
|
$
|
143
|
$
|
189
|
||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$1,
$-, $(1) and $2, respectively
|
1
|
(1
|
)
|
(1
|
)
|
3
|
||||||
Reclassification
adjustments for (gains) included in net income, net of taxes of
$1,
$-,
$2 and $-, respectively
|
(1
|
)
|
-
|
(3
|
)
|
-
|
||||||
Total
comprehensive income, net of taxes
|
$
|
92
|
$
|
131
|
$
|
139
|
$
|
192
|
||||
50
|
Three
Months
|
Six
Months
|
||||||||||
|
|
2006
|
|
|
2005
|
|
|
2006
|
2005
|
|||
CIPS:
|
||||||||||||
Net
income
|
$
|
15
|
$
|
7
|
$
|
14
|
$
|
15
|
||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$-,
$(1), $(1) and $3, respectively
|
-
|
(2
|
)
|
(2
|
)
|
4
|
||||||
Reclassification
adjustments for (gains) included in net income, net of taxes of
$1,
$1,
$2 and $ -, respectively
|
(1
|
)
|
(1
|
)
|
(3
|
)
|
(1
|
)
|
||||
Total
comprehensive income, net of taxes
|
$
|
14
|
$
|
4
|
$
|
9
|
$
|
18
|
||||
Genco:
|
||||||||||||
Net
income
|
$
|
2
|
$
|
31
|
$
|
8
|
$
|
62
|
||||
Unrealized
(loss) on derivative hedging instruments, net of taxes of $-, $-,
$- and
$
-, respectively
|
-
|
-
|
-
|
(1
|
)
|
|||||||
Total
comprehensive income, net of taxes
|
$
|
2
|
$
|
31
|
$
|
8
|
$
|
61
|
||||
CILCORP:
|
||||||||||||
Net
income
|
$
|
1
|
$
|
2
|
$
|
9
|
$
|
11
|
||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes (benefit)
of
$(2),
$(1), $(7) and $7, respectively
|
(3
|
)
|
(1
|
)
|
(11
|
)
|
12
|
|||||
Reclassification
adjustments for (gains) losses included in net income, net of
taxes
of $-, $-, $3 and $-, respectively
|
-
|
(1
|
)
|
(4
|
)
|
1
|
||||||
Total
comprehensive income (loss), net of taxes
|
$
|
(2
|
)
|
$
|
-
|
$
|
(6
|
)
|
$
|
24
|
||
CILCO:
|
||||||||||||
Net
income
|
$
|
8
|
$
|
10
|
$
|
25
|
$
|
26
|
||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes
(benefit)
of
$(2),
$(1), $(7), and $7, respectively
|
(3
|
)
|
(1
|
)
|
(11
|
)
|
11
|
|||||
Reclassification
adjustments for (gains) included in net income, net of taxes
of
$-,
$-,
$3 and $-, respectively
|
-
|
(1
|
)
|
(4
|
)
|
-
|
||||||
Total
comprehensive income, net of taxes
|
$
|
5
|
$
|
8
|
$
|
10
|
$
|
37
|
||||
IP:
|
||||||||||||
Net
income
|
$
|
16
|
$
|
15
|
$
|
20
|
$
|
37
|
||||
Unrealized
(loss) on derivative hedging instruments, net of taxes
(benefit)
of
$-,
$-,
$(1) and $-, respectively
|
-
|
-
|
(1
|
)
|
-
|
|||||||
Reclassification
adjustments for losses included in net income, net of
taxes
(benefit) of
$-, $-, $(1) and $-, respectively
|
-
|
-
|
1
|
-
|
||||||||
Total
comprehensive income, net of taxes
|
$
|
16
|
$
|
15
|
$
|
20
|
$
|
37
|
(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 our assumptions at December 31, 2005, and
assuming continuation of the recently expired federal interest rate relief
beyond 2006, in order to maintain minimum funding levels for Ameren’s pension
plans, we do not expect future contributions to be required until 2011 at
which
time we would expect a required contribution of $100 million to $150 million.
If
federal interest rate relief is not continued in its most recent form, $200
million to $300 million may need to be funded in 2009 to 2010 based on other
recent federal legislative proposals. 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. Ameren
is
considering whether to make voluntary contributions in the second half of
2006.
Ameren
made a contribution to its postretirement benefit plan of $37 million in
the
second quarter of 2006 as compared to $35 million in the second quarter of
the
prior year.
The
following tables present the components of the net periodic benefit cost
for our
pension and postretirement benefit plans for the three months and six months
ended June 30, 2006 and 2005:
Pension
Benefits(a)
|
||||||||||||
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Service
cost
|
$
|
15
|
$
|
14
|
$
|
31
|
$
|
29
|
||||
Interest
cost
|
43
|
41
|
86
|
83
|
||||||||
Expected
return on plan assets
|
(49
|
)
|
(45
|
)
|
(98
|
)
|
(91
|
)
|
||||
Amortization
of:
|
||||||||||||
Prior
service cost
|
3
|
3
|
5
|
5
|
||||||||
Actuarial
loss
|
10
|
9
|
21
|
19
|
||||||||
Net
periodic benefit cost
|
$
|
22
|
$
|
22
|
$
|
45
|
$
|
45
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant
subsidiaries.
|
51
Postretirement
Benefits(a)
|
||||||||||||
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Service
cost
|
$
|
5
|
$
|
5
|
$
|
11
|
$
|
11
|
||||
Interest
cost
|
15
|
17
|
33
|
36
|
||||||||
Expected
return on plan assets
|
(11
|
)
|
(11
|
)
|
(23
|
)
|
(23
|
)
|
||||
Amortization
of:
|
||||||||||||
Transition
obligation
|
1
|
1
|
1
|
1
|
||||||||
Prior
service cost
|
(2
|
)
|
(1
|
)
|
(3
|
)
|
(2
|
)
|
||||
Actuarial
loss
|
7
|
9
|
17
|
19
|
||||||||
Net
periodic benefit cost
|
$
|
15
|
$
|
20
|
$
|
36
|
$
|
42
|
(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 proportional 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 six months ended June 30,
2006
and 2005:
Pension
Costs
|
||||||||||||
Three
Months
|
|
Six
Months
|
|
|||||||||
|
|
2006
|
2005
|
2006
|
2005
|
|||||||
UE
|
$
|
13
|
$
|
13
|
$
|
26
|
$
|
26
|
||||
CIPS
|
3
|
3
|
6
|
6
|
||||||||
Genco
|
1
|
2
|
3
|
4
|
||||||||
CILCORP
|
3
|
3
|
5
|
6
|
||||||||
CILCO
|
4
|
5
|
7
|
9
|
||||||||
IP
|
2
|
1
|
4
|
3
|
Postretirement
Costs
|
||||||||||||
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
UE
|
$
|
8
|
$
|
11
|
$
|
19
|
$
|
22
|
||||
CIPS
|
2
|
3
|
5
|
6
|
||||||||
Genco
|
1
|
1
|
2
|
2
|
||||||||
CILCORP
|
1
|
2
|
4
|
6
|
||||||||
CILCO
|
2
|
3
|
7
|
9
|
||||||||
IP
|
3
|
3
|
7
|
6
|
NOTE
12 - SEGMENT
INFORMATION
Ameren’s
reportable segment Utility Operations comprises its electric generation and
electric and gas transmission and distribution operations. It includes the
operations of UE, CIPS, Genco, CILCORP, CILCO and IP. Ameren’s
reportable segment Other consists of the parent holding company, Ameren
Corporation.
The
accounting policies for segment data are the same as those described in Note
1 -
Summary of Significant Accounting
Policies. Segment data includes intersegment revenues, as well as a charge
for
allocating costs of administrative support services to each of the operating
companies, which in each case is eliminated upon consolidation. Ameren Services
allocates administrative support services based on various factors, such
as head
count, number of customers, and total assets.
The
following table presents information about the reported revenues and net
income
of Ameren for the three months and six months ended June 30, 2006 and
2005:
Utility
Operations
|
Other
|
Reconciling
Items(a)
|
Total
|
|||||||||
Three
Months 2006:
|
||||||||||||
Operating
revenues
|
$
|
1,982
|
$
|
-
|
$
|
(432
|
)
|
$
|
1,550
|
|||
Net
income
|
121
|
2
|
-
|
123
|
||||||||
Three
Months 2005:
|
||||||||||||
Operating
revenues
|
$
|
1,956
|
$
|
-
|
$
|
(372
|
)
|
$
|
1,584
|
|||
Net
income
|
186
|
(1
|
)
|
-
|
185
|
|||||||
Six
Months 2006:
|
||||||||||||
Operating
revenues
|
$
|
4,234
|
$
|
-
|
$
|
(884
|
)
|
$
|
3,350
|
|||
Net
income
|
192
|
1
|
-
|
193
|
52
|
Utility
Operations
|
|
|
Other
|
Reconciling Items(a) |
|
Total
|
Six
Months 2005:
|
||||||||||||
Operating
revenues
|
$
|
3,900
|
$
|
-
|
$
|
(697
|
)
|
$
|
3,203
|
|||
Net
income
|
311
|
(5
|
)
|
-
|
306
|
(a) |
Elimination
of intercompany revenues.
|
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
OVERVIEW
Ameren
Executive Summary
Ameren’s
second quarter and first half of 2006 earnings were lower than the strong
earnings achieved last year. Several
factors contributed to Ameren’s decreased earnings versus the year-ago periods.
Electric margins were negatively impacted by higher fuel and purchased
power
costs due primarily to increased coal and related transportation costs,
an
unplanned outage at our Callaway nuclear plant and milder winter weather.
In
addition, Ameren incurred additional costs of operating in the MISO Day
Two
Energy Market in the first six months of 2006 because MISO Day Two operations
did not commence until the second quarter last year. Incremental costs
resulting
from the December 2005 breach of the upper reservoir at UE’s Taum Sauk
hydroelectric pumped-storage plant also negatively impacted second quarter
and
first half 2006 earnings. Significant planned power plant outages and some
unplanned outages reduced second quarter 2006 earnings as compared to the
prior-year period. These factors offset increased margins from interchange
sales
and organic growth compared to the second quarter and first six months
of last
year.
In
Illinois, we are moving into a critical stage as the scheduled September
2006
power procurement auction fast approaches, the Illinois delivery service
rate
cases come to a close, and the Illinois fall legislative session commences
in
November. In delivery services rate filings made in late December 2005,
CIPS,
CILCO and IP requested a total combined annual electric revenue increase
of
approximately $200 million. 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. The Illinois attorney general
also
filed rebuttal testimony, which we estimate would result in revenue increases
aggregating approximately $100 million. The ICC has until November of this
year
to issue a final decision in these cases. As a result of the potential
increases
to ratepayers from these requested increases and the transition to market-based
power costs, there have been two pieces of legislation proposed in Illinois.
One
proposal includes a potential extension of the rate freeze through 2010,
which
we believe is without legal merit. 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 these companies and Ameren. Following the introduction
of the
rate freeze proposal, a second separate and constructive piece of legislation
was introduced, which authorized the issuance of securitization bonds.
This
approach has the effect of spreading over the life of the bonds, a period
of up
to 10 years, the potentially significant initial electric rate increase
for
residential customers that would otherwise be necessary to pay the power
procurement costs on a current basis. In June 2006, CIPS, CILCO and IP
filed a
proposal with the ICC for a rate increase phase-in and revenue securitization
plan for residential customers similar to the securitization legislation
that
was introduced that would result in deferral of power supply costs for
2007 and
2008.
In
early
July, 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 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. We expect a decision from the MoPSC on both filings by June
2007.
On
July
19, 2006 and July 21, 2006, UE’s, CIPS’ and IP’s service territories were hit by
severe storms, which included tornados, that resulted in the loss of power
to
approximately 700,000 customers combined. Through the dedication of a work
force
of 5,200 people, including our employees, contractors and utility workers
from
13 states, we restored service to all of our customers within nine days.
The
full financial impact of these storms has not yet been determined, but
UE, CIPS
and IP have incurred unanticipated costs, and the loss of electric margins
as a
result of these devastating storms.
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
53
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.
RESULTS
OF OPERATIONS
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. Our 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.
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 to reduce our exposure
to
commodity risks 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 decreased to $123 million, or 60 cents per share, in the second
quarter of 2006 from $185 million, or 93 cents per share, in the second
quarter
of 2005. Ameren’s net income decreased $113 million to $193 million, or 94 cents
per share, for the six months ended June 30, 2006, compared to earnings
of $306
million, or $1.55 per share, in the first six months of 2005. Earnings
were
negatively impacted for the three-month and six-month periods by increased
fuel
and purchased power costs, milder weather, lower prices for interchange
sales,
an unscheduled outage at UE’s Callaway nuclear plant in the second quarter of
2006, costs associated with an upper reservoir breach in December 2005
at UE’s
Taum Sauk plant and incremental costs of operating in the MISO Day Two
Energy
Market. Decreased availability of coal-fired power plants also reduced
second
quarter 2006 earnings as compared to the prior-year period. Additionally,
an
increase in the number of common shares outstanding in the current year
periods
reduced Ameren’s earnings per share. Increased margins on interchange sales at
EEI and organic growth partially offset the impact of these unfavorable
items on
current year earnings.
54
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 six months ended June
30, 2006 and 2005:
Three
Months
|
Six
Months
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
|||||||||
Net
income (loss):
|
||||||||||||
UE(a)
|
$
|
90
|
$
|
130
|
$
|
140
|
$
|
186
|
||||
CIPS
|
15
|
7
|
13
|
14
|
||||||||
Genco(a)
|
2
|
31
|
8
|
62
|
||||||||
CILCORP(a)
|
1
|
2
|
9
|
11
|
||||||||
IP
|
16
|
15
|
19
|
36
|
||||||||
Other(b)
|
(1
|
)
|
-
|
4
|
(3
|
)
|
||||||
Ameren
net income
|
$
|
123
|
$
|
185
|
$
|
193
|
$
|
306
|
(a) |
Includes
earnings from market-based interchange power sales that provided
the
following contributions to net income for the three-month and six-month
periods, respectively:
|
UE:
2006 - $14 million, $34 million
2005
- $25 million, $46 million
Genco: 2006
- $3 million, $10 million
2005
- $15 million, $27 million
CILCORP:
2006 - $5 million, $12 million
2005 - $4 million, $9 million
(b) |
Includes
earnings from non-rate-regulated operations and a 40% interest
in EEI held
by Resources Company, corporate general and administrative expenses,
and
intercompany eliminations.
|
Electric
Operations
The
following table presents the favorable (unfavorable) variations in electric
margins, defined as electric revenues less fuel and purchased power costs,
for
the three months and six months ended June 30, 2006, as compared with the
year-ago periods. We consider electric and interchange margins useful measures
to analyze the change in profitability of our electric operations between
periods. We have included the analysis below as a complement to the financial
information we provide in accordance with GAAP. However, electric and
interchange 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)
|
$
|
(16
|
)
|
$
|
(8
|
)
|
$
|
(2
|
)
|
$
|
-
|
$
|
(2
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
|
Growth
and other (estimate)
|
(23
|
)
|
(5
|
)
|
19
|
(2
|
)
|
2
|
3
|
7
|
|||||||||||
Interchange
revenues
|
10
|
(26
|
)
|
(7
|
)
|
(26
|
)
|
(2
|
)
|
(2
|
)
|
-
|
|||||||||
Total
|
$
|
(29
|
)
|
$
|
(39
|
)
|
$
|
10
|
$
|
(28
|
)
|
$
|
(2
|
)
|
$
|
(1
|
)
|
$
|
3
|
||
Fuel
and purchased power change:
|
|||||||||||||||||||||
Fuel:
|
|||||||||||||||||||||
Generation
and other
|
$
|
15
|
$
|
6
|
$
|
-
|
$
|
13
|
$
|
-
|
$
|
2
|
$
|
-
|
|||||||
Price
|
(21
|
)
|
(14
|
)
|
-
|
(4
|
)
|
(3
|
)
|
(3
|
)
|
-
|
|||||||||
Purchased
power
|
(33
|
)
|
(2
|
)
|
(8
|
)
|
(21
|
)
|
7
|
7
|
(6
|
)
|
|||||||||
Total
|
$
|
(39
|
)
|
$
|
(10
|
)
|
$
|
(8
|
)
|
$
|
(12
|
)
|
$
|
4
|
$
|
6
|
$
|
(6
|
)
|
||
Net
change in electric margins
|
$
|
(68
|
)
|
$
|
(49
|
)
|
$
|
2
|
$
|
(40
|
)
|
$
|
2
|
$
|
5
|
$
|
(3
|
)
|
|||
Six
Months
|
|||||||||||||||||||||
Electric
revenue change:
|
|||||||||||||||||||||
Effect
of weather (estimate)
|
$
|
(30
|
)
|
$
|
(14
|
)
|
$
|
(7
|
)
|
$
|
-
|
$
|
(3
|
)
|
$
|
(3
|
)
|
$
|
(6
|
)
|
|
Growth
and other (estimate)
|
(6
|
)
|
(6
|
)
|
64
|
13
|
7
|
8
|
16
|
||||||||||||
Interchange
revenues
|
96
|
15
|
(15
|
)
|
(19
|
)
|
(7
|
)
|
(7
|
)
|
-
|
||||||||||
Total
|
$
|
60
|
$
|
(5
|
)
|
$
|
42
|
$
|
(6
|
)
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
10
|
|||
Fuel
and purchased power change:
|
|||||||||||||||||||||
Fuel:
|
|||||||||||||||||||||
Generation
and other
|
$
|
-
|
$
|
3
|
$
|
-
|
$
|
4
|
$
|
-
|
$
|
1
|
$
|
-
|
|||||||
Price
|
(47
|
)
|
(30
|
)
|
-
|
(14
|
)
|
(3
|
)
|
(3
|
)
|
-
|
|||||||||
Purchased
power
|
(108
|
)
|
(31
|
)
|
(39
|
)
|
(68
|
)
|
14
|
14
|
(26
|
)
|
|||||||||
Total
|
$
|
(155
|
)
|
$
|
(58
|
)
|
$
|
(39
|
)
|
$
|
(78
|
)
|
$
|
11
|
$
|
12
|
$
|
(26
|
)
|
||
Net
change in electric margins
|
$
|
(95
|
)
|
$
|
(63
|
)
|
$
|
3
|
$
|
(84
|
)
|
$
|
8
|
$
|
10
|
$
|
(16
|
)
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
55
Ameren
Ameren’s
electric margin decreased by $68 million, or 7%, and $95 million or 6%,
for the
three months and six months ended June 30, 2006, compared with the same
periods
in 2005. Ameren’s decrease in electric margins was impacted by:
· |
unfavorable
weather conditions as evidenced by an 8% decline in cooling degree-days
for both the three months and six months ended June 30, 2006
and an 11%
decrease in heating degree-days for the six months ended June
30, 2006,
compared with the same periods in 2005. In addition, spring storms
caused
an unscheduled plant outage in the first quarter of
2006;
|
· |
incremental
fees of $6 million levied by FERC in the first quarter of 2006,
upon
completion of its cost study for generation benefits provided
to UE’s
Osage hydroelectric plant;
|
· |
a
14% increase in both the second quarter and first half of 2006
in coal and
transportation prices resulting from increased global demand
for coal;
|
· |
MISO
Day Two Energy Market costs, which were comparable in the second
quarter
and $21 million higher for the six months ended June 30, 2006,
compared
with the same periods in 2005;
|
· |
the
unavailability of UE’s Taum Sauk hydroelectric plant totaling an estimated
$4 million and $10 million in the second quarter and first half
of
2006;
|
· |
an
unscheduled outage at UE’s Callaway nuclear plant, which reduced electric
margins by an estimated $20 million, and planned and unplanned
outages at
certain of UE’s and Genco’s coal-fired plants, primarily in the second
quarter of 2006;
|
· |
lower
wholesale margins of approximately $6 million and $12 million
in the
second quarter and first half of 2006 at Marketing Company as
a result of
the expiration of several large contracts in 2005;
and
|
· |
reduced
transmission revenues due primarily to a decrease in Marketing
Company’s
non-service territory load for UE, CIPS, CILCORP, CILCO and
IP.
|
The
decrease in Ameren’s electric margins was partially offset by:
· |
an
increase in margins on interchange sales of $13 million or 17%,
and $62
million or 42%, over the prior three and six month periods primarily
because of the increased sale of power from EEI resulting from
the
expiration of its affiliate cost-based sales contract on December
31,
2005; and
|
· |
sales
to Noranda, which added approximately $11 million and $17 million
in
electric margins at UE for the second quarter and first six months
of
2006, respectively.
|
UE
UE’s
electric margin decreased by $49 million, or 9%, and $63 million, or
7%, for the
three months and six months ended June 30, 2006, compared to the same
periods in
2005. The decrease in electric margins was due to:
· |
unfavorable
weather conditions as evidenced by a 10% decline in cooling degree-days
for both the second quarter and the first half of the year and
a 10%
decrease in heating degree-days for the six months ended June
30, 2006
compared with the same period in 2005;
|
· |
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
$6
million for the second quarter and $24 million for the first
half of
2006;
|
· |
lower
margins on interchange sales as a result of power plant unavailability.
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 $5 million
and $14
million in incremental margins on interchange sales for UE for
the three
months and six months ended June 30, 2006,
respectively.
|
· |
an
11% and 14% increase in coal and related transportation prices
for the
second quarter and first six months of 2006, compared with the
same
periods in 2005;
|
· |
incremental
fees of $6 million levied by FERC in the first quarter of 2006
for
generation benefits provided to UE’s Osage hydroelectric
plant;
|
· |
the
unavailability of UE’s Taum Sauk hydroelectric
plant;
|
· |
unscheduled
outages at UE’s Callaway nuclear plant and certain of its coal-fired
plants primarily in the second quarter of 2006 compared with
the same
period in 2005;
|
· |
MISO
Day Two Energy Market costs, which were comparable for the three
months
ended June 30, 2006, and $14 million higher for the six months
ended June
30, 2006, compared with the same periods in 2005;
and
|
· |
the
expiration of a cost-based power supply contract with EEI on
December 31,
2005.
|
The
decrease in UE’s electric margins for the three months and six months ended June
30, 2006, compared with the same periods in 2005, was partially offset
by sales
to Noranda.
CIPS
CIPS’
electric margin increased by $2 million, or 3%, for the three months
and $3
million, or 3%, for the six months
56
ended
June 30, 2006, compared to the same periods in 2005, primarily because
of:
· |
the
transfer to CIPS of UE’s Illinois service territory on May 2, 2005 which
generated an incremental margin of $4 million in the second quarter
and
$16 million in the first half of 2006;
and
|
· |
customers
switching back to CIPS from Marketing Company because tariff
rates were
below market rates for power.
|
CIPS’
increase in electric margin was reduced by increased MISO Day Two Energy
Market
costs, totaling $2 million for the six months ended June 30, 2006, compared
with
the same period in 2005. Unfavorable weather conditions as evidenced
by a 13%
decrease in heating degree-days also lowered CIPS’ electric margins for the six
months ended June 30, 2006, compared with the same period in 2005.
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 $7 million
and
$15 million for the three months and six months ended June 30,
2006.
Genco
Genco’s
electric margin decreased by $40 million, or 31%, and $84 million, or
33%, for
the three months and six months ended June 30, 2006, compared with the
same
periods in 2005, primarily because of:
· |
lower
wholesale margins as Genco purchased higher-cost power from affiliates
and
third parties to serve a greater load, primarily to supply power
to serve
the Illinois service territory transferred to CIPS in May 2005;
|
· |
an
11% increase in coal and transportation prices for the three
months and
six months ended June 30, 2006, compared with the same periods
in
2005;
|
· |
a
scheduled outage in the second quarter of a major coal-fired
unit;
|
· |
lower
margins on interchange sales for the three months and six months
ended
June 30, 2006, compared with the same periods in 2005 primarily
because of
reduced power plant availability and a $5 million and $14 million
reduction due to the amendment of the JDA between UE and Genco;
and
|
· |
higher
emission allowance utilization costs.
|
Genco’s
decrease in electric margins was reduced by an increase in revenues 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.
CILCORP
and CILCO
For
the
three and six month periods ended June 30, 2006, CILCORP’s electric margin
increased by $2 million, or 3%, and $8 million, or 7%, respectively,
and CILCO’s
electric margin increased $5 million, or 8%, and $10 million, or 8%,
respectively, as compared to 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 $2 million and
$3 million
for the three and six month periods, respectively;
and
|
· |
increases
in margins on interchange sales of $1 million and $5 million
in the three
and six month periods, respectively.
|
The
increase in electric margins was reduced by higher MISO Day Two Energy
Market
costs and unfavorable weather conditions as evidenced by an 18% decrease
in
cooling degree-days for both the three and six month periods and an 8%
decrease
in heating degree-days for the six months ended June 30, 2006.
IP
IP’s
electric margin decreased by $3 million, or 3%, for the three months and
$16
million, or 9%, for the six months ended June 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; and
|
· |
unfavorable
weather conditions including a 12% decrease in heating degree-days
for the
six months ended June 30, 2006.
|
The
decrease in IP’s electric margins in the three months and six months ended June
30, 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.
57
Gas
Operations
The
following table presents the favorable (unfavorable) variations in gas margins,
defined as gas revenues less gas purchased for resale, for the three months
and
six months ended June 30, 2006, compared with the year-ago periods. We consider
gas margin to be a useful measure of the change in profitability of our gas
utility operations between periods. The table below complements the financial
information we provide in accordance with GAAP. However, gas margin may not
be a
presentation defined under GAAP. Our presentation may not be comparable to
other
companies’ presentations or more useful than the GAAP information we provide
elsewhere in this report.
Three
Months
|
Six
Months
|
|||
Ameren(a)
|
$
|
-
|
$
|
(6)
|
UE
|
(3)
|
(8)
|
||
CIPS
|
2
|
2
|
||
CILCORP
|
(1)
|
(4)
|
||
CILCO
|
(2)
|
(5)
|
||
IP
|
2
|
5
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
Ameren
Ameren’s
gas margin was comparable for the three months but decreased by $6 million,
or
3%, for the six months ended June 30, 2006, over the same periods in 2005.
Ameren’s
decrease in gas margin for the six months ended June 30, 2006, compared with
the
same period in 2005 was primarily due to mild weather conditions as evidenced
by
an 11% decrease in heating degree-days. Residential and commercial gas volume
sales decreased 11% and 10%, respectively, for the six months ended June
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 half of
2006.
Ameren’s
gas margin was positively impacted in the second quarter over the same period
in
2005 by the effect of IP’s rate increase that added revenues of $2 million. The
increase in gas margin was offset in part by mild weather conditions that
reduced gas margins as heating degree-days were 16% below a mild 2005 second
quarter.
UE
UE’s
gas
margin decreased by $3 million, or 23%, for the three months and $8 million,
or
19%, for the six months ended June 30, 2006, compared with the same periods
in
2005. UE’s decrease in gas margins for the three months ended June 30, 2006,
compared with the same period in 2005, was due to mild weather conditions,
as
evidenced by a 22% decrease in heating degree-days. UE’s decrease in gas margins
for the six months ended June 30, 2006, compared with the same period in
2005,
was due to the transfer of UE’s Illinois service territory to CIPS in May 2005,
which reduced gas margins by $3 million, and mild weather conditions, as
evidenced by a 10% decrease in heating degree-days in UE’s service territory.
Residential and commercial gas sales decreased 39% and 22%, respectively,
for
the three months and 26% and 19%, respectively, for the six months ended
June
30, 2006, compared with the same periods in 2005.
CIPS
CIPS’
gas
margin increased by $2 million or 17%, for the three months and $2 million
or
5%, for the six months ended June 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
weather as evidenced by a 13% decrease in heating degree-days for the six
months
ended June 30, 2006, as compared with the same period in 2005.
CILCORP
and CILCO
CILCORP’s
and CILCO’s gas margins decreased by $1 million, or 6%, and $2 million, or 11%,
respectively, for the three months and $4 million, or 8%, and $5 million,
or
10%, respectively, for the six months ended June 30, 2006, over the same
periods
in 2005. This decrease was primarily as a result of mild weather conditions
as
heating degree-days in the six months ended June 30, 2006, were 8% below
the
number of days in the six months ended June 30, 2005 in CILCO’s service
territory.
IP
IP’s
gas
margin increased by $2 million, or 7%, for the three months and $5 million,
or
6%, for the six months ended June 30, 2006, over the same periods in 2005,
primarily because of a rate increase effective in May 2005 that added revenues
of $2 million and $6 million, respectively. This increase was reduced by
extremely mild weather conditions as evidenced by a 12% decrease in heating
degree-days in the first half of 2006 as compared with the year-ago period
in
IP’s service territory. Residential and commercial gas sales decreased 9% and
7%, respectively, for the three months and 11% and 13%, respectively, for
the
six months ended June 30, 2006, compared with the same periods in
2005.
Operating
Expenses and Other Statement of Income Items
Other
Operations and Maintenance
Variations
in other operations and maintenance expenses at the Ameren Companies for
the
three months and six months ended June 30, 2006, compared with the same periods
in 2005 were as follows:
58
Ameren
Three
months and six months - Other operations and maintenance expenses increased
$19
million and $22 million primarily because of $10 million of costs in the
second
quarter of 2006 related to the December 2005 reservoir breach at UE’s Taum Sauk
plant, losses on sales of leveraged lease assets in the second quarter of
2006
that increased other operations and maintenance expenses by $7 million, higher
power plant maintenance expenses due to the timing of maintenance outages,
an
increase in legal fees for environmental issues and general litigation, and
increased transmission and distribution expenses. Reducing the impact of
these
items in the second quarter of 2006 was a reduction in bad debt
expense.
UE
Three
months - Other operations and maintenance expenses increased $3 million
primarily because of incremental costs related to the Taum Sauk plant incident
along with increased legal fees. Reducing the impact of these unfavorable
items
were reduced labor and employee benefit costs.
Six
months - Other operations and maintenance expenses decreased $7 million
primarily because of the transfer of UE’s Illinois service territory to CIPS in
May 2005, which resulted in a decrease in other operations and maintenance
expenses of $7 million. Additionally, lower injuries and damages expenses
due in
part to the settlement of claims and decreased labor and employee benefit
costs
resulted in a reduction in other operations and maintenance expenses. Reducing
the impact of these favorable items were increased legal fees and additional
costs related to the Taum Sauk plant incident.
CIPS
Three
months - Other operations and maintenance expenses were comparable between
periods.
Six
months - Other operations and maintenance expenses increased $6 million because
of the transfer of UE’s Illinois service territory to CIPS in May 2005, which
resulted in an increase in other operations and maintenance expenses of $7
million.
Genco
Three
months and six months - Other operations and maintenance expenses increased
$9
million and $3 million primarily because of higher maintenance expenses as
a
result of increased power plant maintenance outages in the current year
periods.
CILCORP
and CILCO
Three
months and six months - Other operations and maintenance expenses increased
$9
million and $8 million at CILCORP, and $12 million and $9 million at CILCO,
primarily as a result of losses on sales of leveraged lease assets in the
second
quarter of 2006. The losses on leveraged leases in other operations and
maintenance expenses were partially offset by a tax benefit reflected in
income
taxes.
IP
Three
months - Other operations and maintenance expenses were comparable between
periods.
Six
months - Other operations and maintenance expenses increased $18 million
primarily because of higher transmission and distribution, information
technology, bad debt and rental expenses.
Depreciation
and Amortization
Variations
in depreciation and amortization expenses at the Ameren Companies for the
three
months and six months ended June 30, 2006, compared with the same periods
in
2005 were as follows:
Ameren
Three
months - Depreciation and amortization expenses increased $5 million primarily
because of capital additions.
Six
months - Depreciation and amortization expenses increased $13 million primarily
as a result of capital additions and the impairment of an intangible asset
associated with the CILCORP acquisition.
UE
Three
months and six months - Depreciation and amortization expenses increased
$5
million and $9 million, respectively, 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 the prior year. Additionally, depreciation increased $1 million
and $3
million, respectively, in the three months and six months ended June 30,
2006,
due to CTs transferred to UE from Genco in May 2005. Reducing the impact
of
these increases was a reduction of depreciation due to the transfer of property
to CIPS in the Illinois service territory transfer in May 2005.
CIPS
Three
months - Depreciation and amortization expenses were comparable between
periods.
59
Six
months - Depreciation and amortization expenses increased $3 million primarily
because of depreciation on property transferred to CIPS from UE in the
prior-year Illinois service territory transfer along with capital
additions.
CILCORP
Three
months - Depreciation and amortization expenses were comparable between
periods.
Six
months - Depreciation and amortization expenses increased $5 million primarily
because of the impairment of an intangible asset established in conjunction
with
Ameren’s acquisition of CILCORP.
IP
Three
months - Depreciation and amortization expenses were comparable between
periods.
Six
months - Depreciation and amortization expenses decreased $3 million primarily
because of write-offs of software in the prior year.
Genco
and CILCO
Three
months and six months - Depreciation and amortization expenses were comparable
between periods.
Taxes
Other Than Income Taxes
Variations
in taxes other than income taxes at the Ameren Companies for the three months
and six months ended June 30, 2006, compared with the same periods in 2005
were
as follows:
Ameren
Three
months - Taxes other than income taxes decreased $5 million primarily because
of
lower payroll taxes.
Six
months - Taxes other than income taxes increased $17 million primarily as
a
result of higher gross receipts taxes and higher property taxes, primarily
at
Genco.
UE
Three
months - Taxes other than income taxes were comparable between
periods.
Six
months - Taxes other than income taxes increased $4 million primarily as
a
result of higher gross receipts taxes.
CIPS
Three
months - Taxes other than income taxes were comparable between
periods.
Six
months - Taxes other than income taxes increased $6 million primarily as
a
result of higher gross receipts and excise taxes.
Genco
Three
months - Taxes other than income taxes were comparable between
periods.
Six
months - Taxes other than income taxes increased $8 million primarily because
of
higher property taxes due to an $8 million tax settlement that was received
in
the first quarter of 2005 that did not recur in 2006.
CILCORP
and CILCO
Three
months - Taxes other than income taxes were comparable between
periods.
Six
months - Taxes other than income taxes increased $2 million and $3 million
at
CILCORP and CILCO, respectively, primarily as a result of higher excise
taxes.
IP
Three
months and six months - Taxes other than income taxes were comparable between
periods.
Other
Income and Expenses
Variations
in other income and expenses at the Ameren Companies for the three months
and
six months ended June 30, 2006, compared with the same periods in 2005 were
as
follows:
Ameren
Three
months and six months - Miscellaneous income decreased $2 million and $5
million
primarily as a result of lower capitalization of equity funds used during
construction in the current year periods. Miscellaneous expense decreased
$5
million and $6 million primarily due to the write-off of unrecoverable natural
gas costs in the prior year as noted below.
UE
Three
months - Other income and expenses were comparable between periods.
60
Six
months - Miscellaneous income decreased $5 million primarily as a result
of
lower capitalization of equity funds used during construction in the current
year period. Miscellaneous expense was comparable between periods.
CIPS
Three
months and six months - Miscellaneous income was comparable between periods.
Miscellaneous expense decreased $4 million and $3 million primarily as a
result
of the write-off of unrecoverable natural gas costs in the prior
year.
CILCORP
Three
and
six months - Miscellaneous income was comparable between periods. Miscellaneous
expense decreased $2 million and $3 million primarily as a result of the
write-off of unrecoverable natural gas costs in the prior year.
IP
Three
months - Other income and expenses were comparable between periods.
Six
months - Miscellaneous income decreased $2 million primarily as a result
of
lower capitalization of equity funds used during construction and reduced
investment income in the current year period. Miscellaneous expense was
comparable between periods.
Genco
and CILCO
Three
months and six months - Other income and expenses were comparable between
periods.
Interest
Variations
in interest expense at the Ameren Companies for the three months and six
months
ended June 30, 2006, compared with the same periods in 2005 were as
follows:
Ameren
Three
months and six months - Interest expense increased $3 million and $5 million
primarily because of items noted below at the various Ameren Companies,
partially offset by a reduction in interest expense resulting from the
repurchase and retirement of Ameren’s $95 million of senior notes in February
2005.
UE
Three
months and six months - Interest expense increased $10 million and $20 million
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 resulting from the purchase of CTs in the
first
quarter of 2006.
Genco
Three
months and six months - Interest expense decreased $4 million and $10 million
primarily because of the maturity of $225 million of senior notes in November
2005.
CIPS, CILCORP,
CILCO and IP
Three
months and six months - Interest expense was comparable between
periods.
Income
Taxes
Variations
in income tax expense at the Ameren Companies for the three months and six
months ended June 30, 2006, compared with the same periods in 2005 were as
follows:
Ameren
Three
months and six months - Income taxes decreased primarily because of lower
pretax
income along with items noted below at the various Ameren
Companies.
UE
Three
months and six months - Income taxes decreased primarily because of lower
pretax
income, partially offset by permanent tax items.
CIPS
Three
months and six months - Income taxes decreased in the second quarter of 2006,
despite higher pretax income, due to a favorable federal audit settlement.
Income taxes decreased in the six months ended June 30, 2006, primarily because
of lower pretax income and the favorable audit settlement.
Genco
Three
months and six months - Income taxes decreased primarily because of lower
pretax
income.
CILCORP
and CILCO
Three
months and six months - Income taxes decreased primarily because of lower
pretax
income and a tax benefit related to leveraged lease sales.
IP
Three
months and six months - Income tax expense was comparable between periods
for
the three months. Income tax expense decreased in the six months of 2006
primarily because of lower pretax income.
61
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.
For
operating cash flows, Genco principally relies on 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 intend to sell power previously sold under existing contracts through
new
contracts obtained through the Illinois power procurement auction or other
contracts executed with wholesale and retail customers. The amount of power
that
Genco and its 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 short-term
borrowings 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 June 30, 2006, for UE, Genco, CILCORP,
CILCO
and IP. The Ameren Companies will discretionarily reduce their short-term
borrowings with cash from operations or with long-term borrowings.
The
following table presents net cash
provided by (used in) operating, investing and financing activities for the
six
months ended June 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)
|
$
|
570
|
$
|
749
|
$
|
(179)
|
|
$
|
(746)
|
|
$
|
(531)
|
|
$
|
(215)
|
|
$
|
131
|
$
|
(260)
|
|
$
|
391
|
||||
UE
|
227
|
353
|
(126)
|
|
(511)
|
|
(492)
|
|
(19)
|
|
265
|
92
|
173
|
||||||||||||||
CIPS
|
79
|
96
|
(17)
|
|
(23)
|
|
-
|
(23)
|
|
(55)
|
|
(97)
|
|
42
|
|||||||||||||
Genco
|
55
|
132
|
(77)
|
|
(56)
|
|
102
|
(158)
|
|
2
|
(235)
|
|
237
|
||||||||||||||
CILCORP
|
106
|
55
|
51
|
-
|
(64)
|
|
64
|
(86)
|
|
5
|
(91)
|
|
|||||||||||||||
CILCO
|
113
|
77
|
36
|
(42)
|
|
(67)
|
|
25
|
(51)
|
|
(11)
|
|
(40)
|
|
|||||||||||||
IP
|
86
|
149
|
(63)
|
|
(83)
|
|
8
|
(91)
|
|
(2)
|
|
(157)
|
|
155
|
(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 six months of 2006, as compared
with
the first six months of 2005, due primarily to decreases in electric and
gas
margins as discussed in Results of Operations above. Also contributing to
the
decrease was cash used during the first six months of 2006 for payment of
2005
year-end accruals including real estate and property taxes, annual incentive
compensation that was more than it was a year ago because of increased 2005
earnings relative to performance targets, and trade payables that were higher
than normal due to an unusually cold December 2005 and higher natural gas
prices. 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 quarter as a result of increased volume and per unit prices
of
coal inventory purchases because of the alleviation of the coal supply issues
experienced in the 2005 period and higher market prices for coal in the 2006
period. Reducing the 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 cash used for working capital changes that primarily included
increased payments of year-end accruals in the first six months of 2006 as
compared with the year-ago period as discussed above for Ameren. Also
contributing to the decrease were increased income tax payments of $49 million
compared to the year-ago period.
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. However, increased working capital
investment also contributed to the decrease in cash from operations in the
2006
period as compared to the year ago period. The most significant change in
working capital was a $35 million increase in income tax payments 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 six months of 2006 decreased
compared to the 2005 period primarily because of lower operating margins
as
discussed in
62
Results
of Operations. Interest payments were lower in the 2006 period due to
decreased debt outstanding.
Cash
from
operating activities increased for CILCORP and CILCO in the six months ended
June 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 period. Partially offsetting these
positive effects on cash were higher other operations and maintenance expenses
as discussed in Results of Operations. In addition, income tax payments
increased $12 million for CILCO and decreased $3 million for
CILCORP.
IP’s
cash
from operations decreased in the six months ended June 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 income taxes
paid of $6 million in the 2006 period as compared with income tax refunds
of $9
million in the year-ago period, and cash used during the first six months
of
2006 for payment of 2005 year-end accruals including real estate and property
taxes, annual incentive compensation that was more than it was a year ago
due to
increased 2005 earnings relative to performance targets, and trade payables
that
were higher than normal due to an unusually cold December 2005 and higher
natural gas prices.
Cash
Flows from Investing Activities
Ameren’s
increase in cash used in investing activities was primarily because of UE’s
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 decreased $36 million in the first
six months of 2006 as compared with the year-ago period primarily because
fewer
capital resources were allocated to other projects due to the planned CT
acquisitions. Excluding the CTs purchased from Genco and an additional $25
million used to purchase CT equipment from Development Company in the 2005
period, UE’s capital expenditures were only $26 million less in the first six
months of 2006 as compared with the year-ago period. In addition, emission
allowance purchases decreased $54 million in the first six months of 2006
compared to the first six months of 2005. The sale of leveraged lease
investments provided an $11 million benefit to Ameren’s cash from investing
activities as discussed below.
CIPS’
increase in cash used in investing activities for the six months ended June
30,
2006, over the 2005 period was due to a $16 million increase in capital
expenditures. 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. Partially
offsetting these negative effects was an $11 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. CIPS’ 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 six months of 2006
compared to a net source of cash during the same period in 2005. This was
due
primarily to the 2005 transfer of two CTs to UE in 2005 for $241 million.
Genco’s capital expenditures were lower for the six months ended June 30,
2006,
compared
with the 2005 period because 2005 included expenditures due to an extended
planned outage at one of its power plants. Purchases of emission allowances
were
$45 million less in the first six months of 2006 compared to the first six
months of 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
six months ended June 30, 2006, from the sale of its remaining leverage lease
investments. Emission allowance purchases were $9 million less in the
first six months of 2006 compared to the first six months of 2005.
IP
had a
net use of cash in investing activities for the first six months of 2006
compared to a net source of cash in the prior-year period primarily because
of
the absence in the six month period ended June 30, 2006, of proceeds received
in
the first six months of 2005 from repayments received for advances made to
the
money pool in prior periods. In addition, capital expenditures increased
$22
million over the year-ago period due to increased projects 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
63
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
from
financing activities increased for Ameren in the first six months of
2006
from the
year-ago period, primarily because of net short-term debt proceeds of $204
million, which were used to partially fund UE’s CT acquisitions, compared to net
short-term debt repayments of $256 million in the year-ago period. Ameren’s cash
from financing activities also increased from long-term debt issuances of
$232
million at CIPS, CILCO and IP in 2006, which was significantly more than
Ameren’s 2005 long-term debt issuances of $85 million. In addition, long-term
debt redemptions, repurchases, and maturities decreased by $151 million in
2006,
compared to the same period in 2005. Cash from stock proceeds was significantly
less in the 2006 period because proceeds in the 2005 period included the
issuance of 7.4 million shares of common stock related to the settlement
of a
stock purchase obligation in Ameren’s adjustable conversion-rate equity security
units.
UE’s
cash
from financing activities increased for the six months ended June 30,
2006,
as
compared with the 2005 period, primarily because of a $284 million increase
in
net short-term debt proceeds in 2006 compared to combined net money pool
and
short-term debt proceeds of $143 million in the 2005 period, which resulted
in a
$141 million benefit in the 2006 period. In addition, $67 million was received
from CIPS in payment of its intercompany note, and dividend payments decreased
$51 million, both of which benefited cash from financing activities in the
2006
period as compared with the 2005 period. Net cash from financing activities
was
partially used to fund the CT acquisitions.
CIPS’
cash used in financing activities decreased for the six months ended June
30,
2006,
as
compared with the 2005 period, because of a $66 million decrease in payments
to
the money pool in the 2006 period. A $16 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 issuance of $61 million of long-term
debt had a minor net impact on cash from financing activities because the
proceeds were 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 six months of 2006,
compared to a net use of cash for the same period last year. This is primarily
due to Genco having $57 million in net borrowings from the money pool in
the
2006 period, compared to net repayments of $116 million in the prior year
period. In addition, lower intercompany note payments of $52 million in the
2006
period, and a $50 million capital contribution received in 2006 from Ameren
also
benefited Genco’s financing cash flows. Partially offsetting these positive
effects on cash was a $37 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. However, this benefit in the
2006
period was completely offset by the absence in 2006 of a $101 million capital
contribution received in the 2005 period. In addition, in 2006, CILCORP used
cash of $12 million for open market debt repurchases as compared with $6
million
of cash used for repurchases in the 2005 period. CILCORP’s repayments of $30
million on its note payable to Ameren reduced its financing cash flow by
$52
million as compared with the year-ago period because the 2005 period included
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 six months ended June 30, 2006, as compared with the year-ago
period, were increased common stock dividends of $20 million and $30 million
at
CILCORP and CILCO, respectively, in the 2006 period as compared with the
2005
period. In addition, net increases in cash for money pool repayments of $7
million and $4 million at CILCORP and CILCO, respectively, also negatively
impacted cash in the 2006 period.
IP’s
cash
used in financing activities decreased for the six months ended June 30,
2006,
as
compared with the
2005
period, primarily because of lower redemptions and repurchases of long-term
debt
of $67 million and the absence in the 2006 period of $40 million of common
stock
dividend payments made in the 2005 period. IP’s 2006 cash from financing
activities also benefited from the issuance of $75 million of long-term debt
as
compared with no long-term debt proceeds in the year-ago period. A portion
of
the 2006 long-term debt proceeds were used to repay short-term debt consisting
of borrowings under Ameren’s utility money pool.
64
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 - Short-term
Borrowings and Liquidity to our financial statements under Part I, Item 1,
of
this report.
The
following table presents the committed bank credit facilities of the Ameren
Companies and AERG as of June 30, 2006, and July 14, 2006:
Credit
Facility
|
Expiration
|
Amount
Committed
|
Amount
Available
|
||||||
Ameren:
|
|||||||||
Multiyear
revolving(a)(b)
|
July
2010
|
$
|
1,150
|
$
|
756
|
||||
Multiyear
revolving(c)
|
July
2006
|
350
|
350
|
||||||
CIPS,
CILCORP, CILCO, IP and AERG:
|
|
||||||||
Multiyear
revolving(d)
|
January
2010
|
500
|
500
|
(a) |
Ameren
Companies may access this credit facility through intercompany
borrowing
arrangements.
|
(b) |
UE
and Genco are also direct borrowers under this facility. CIPS,
CILCO and
IP were also direct borrowers under this agreement until July 13,
2006.
See Note 3 - Short-term Borrowings and Liquidity to our financial
statements under Part I, Item 1, of this report for discussion
of the
amendment of this facility.
|
(c) |
This
credit facility was terminated on July 14,
2006.
|
(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. The ability
of
CIPS, CILCO, and IP to borrow under this facility is subject to
the
receipt of necessary regulatory approvals. See Note 3 - Short-term
Borrowings and Liquidity to our financial statements under Part
I, Item 1,
of this report for discussion of the new 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 June
30,
2006, Ameren had $51 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 in February 2006, 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
six months ended June 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.
Six
Months
|
||||||||
Month
Issued, Redeemed, Repurchased or Matured
|
2006
|
2005
|
||||||
Issuances
|
||||||||
Long-term
debt
|
||||||||
UE:(a)
|
||||||||
5.00%
Senior secured notes due 2020
|
January
|
$
|
-
|
$
|
85
|
|||
CIPS:
|
||||||||
6.70%
Senior secured notes due 2036
|
June
|
61
|
-
|
|||||
CILCO:
|
||||||||
6.20%
Senior secured notes due 2016
|
June
|
54
|
-
|
|||||
6.70%
Senior secured notes due 2036
|
June
|
42
|
-
|
|||||
IP:
|
|
|||||||
6.25%
Senior secured notes due 2016
|
June
|
75
|
-
|
|||||
Total
Ameren long-term debt issuances
|
$
|
232
|
$
|
85
|
65
|
Six
Months
|
||||||
Month
Issued, Redeemed, Repurchased or Matured
|
2006
|
2005
|
|||||
Common
stock
|
|
|
|||||
Ameren:
|
|||||||
7,402,320
Shares at $46.61(b)
|
May
|
$
|
-
|
$
|
345
|
||
DRPlus
and 401(k)(c)
|
Various
|
57
|
57
|
||||
Total
common stock issuances
|
$
|
57
|
$
|
402
|
|||
Total
Ameren long-term debt and common stock issuances
|
$
|
289
|
$
|
487
|
|||
Redemptions,
Repurchases and Maturities
|
|||||||
Long-term
debt
|
|||||||
Ameren:
|
|||||||
Senior
notes due 2007(d)
|
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
|
||||
IP:
|
|||||||
6.75%
First mortgage bonds due 2005
|
March
|
-
|
70
|
||||
Notes
payable to IP SPT
|
|
||||||
5.54%
Series due 2007
|
Various
|
54
|
-
|
||||
5.38%
Series due 2005
|
Various
|
-
|
46
|
||||
Total
Ameren long-term debt and preferred stock redemptions, repurchases
and
maturities
|
$
|
86
|
$
|
237
|
(a) |
Ameren’s
and UE’s long-term debt increased $240 million as a result of the first
quarter 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) |
Shares
issued upon settlement of the purchase contracts, which were a
component
of the adjustable conversion-rate equity security units.
|
(c) |
Includes
issuances of common stock of 1.1 million shares during the six
months
ended June 30, 2006, under DRPlus and 401(k)
plans.
|
(d) |
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 June 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 4.0 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 June 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 - Short-term Borrowings and Liquidity to our financial statements under
Part
I, Item 1, of this report for a discussion
of the covenants and provisions contained in Ameren’s 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
June
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 will continue to have access to the capital markets. However,
events beyond our control may create uncertainty in the capital markets.
Such
events might increase our cost of capital or adversely affect our ability
to
access the capital markets.
66
Dividends
Dividends
paid by Ameren to shareholders during the first six months of 2006 totaled
$260
million, or $1.27 per share (2005 - $253 million or $1.27 per share).
UE
paid
preferred stock dividends of approximately $1 million on May 15, 2006. CIPS
paid
preferred stock dividends of approximately $1 million on June 30, 2006. CILCO
paid preferred stock dividends of less than $1 million on July 3, 2006. IP
paid
preferred stock dividends of approximately $1 million on August 1, 2006.
The
next preferred dividends are payable on August 15, 2006, September 29, 2006,
October 2, 2006 and November 1, 2006 for UE, CIPS, CILCO and IP,
respectively.
See
Note
3 - Short-term Borrowings 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
June
30, 2006, none of these circumstances existed and as a result, the Ameren
Companies were allowed to pay dividends.
On
July
14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a new $500 million
credit facility which limits a borrower to capital stock dividend payments
of
$10 million per year if the borrower has a below investment-grade senior
unsecured credit rating as defined in the new 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.
The other borrowers are not currently limited in their dividend payments
by this
provision of the new credit facility. See Note 3 - Short-term Borrowings
and
Liquidity 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 six months ended June 30,
2006
and 2005.
Six
Months
|
||||||
2006
|
2005
|
|||||
UE
|
$
|
84
|
$
|
135
|
||
CIPS
|
25
|
9
|
||||
Genco
|
71
|
34
|
||||
CILCORP(a)
|
50
|
30
|
||||
IP
|
-
|
40
|
||||
Nonregistrants
|
30
|
5
|
||||
Dividends
paid by Ameren
|
$
|
260
|
$
|
253
|
(a) |
CILCO
paid dividends of $50 million and $20 million for the six months
ended
June 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. 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 $4,327 million,
$1,654 million, $471 million, $642 million, $645 million, $645 million and
$622
million, respectively, as of June 30, 2006. Total other obligations at June
30,
2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $4,799 million,
$1,929 million, $601 million, $642 million, $757 million, $757 million and
$803
million, respectively.
67
Credit
Ratings
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
|
Unsecured
debt
|
A2
|
A3
|
Commercial
paper
|
P-1
|
P-2
|
CIPS:
|
||
Secured
debt
|
A3
|
Baa2
|
Unsecured
debt
|
Baa1
|
Baa3
|
CILCORP:
|
||
Unsecured
debt
|
Baa3
|
Ba1
|
CILCO:
|
||
Secured
debt
|
A3
|
Baa1
|
Unsecured
debt
|
Baa1
|
Baa2
|
Moody’s
confirmed the credit ratings of Ameren and IP, and Genco was unaffected.
Following these actions, Moody’s review for possible downgrade was removed and
replaced with a negative outlook for Ameren, CIPS, CILCORP, CILCO and IP,
and a
stable outlook was assigned to UE and Genco.
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 that are not currently
being
recovered from customers.
|
· |
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.
|
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.
|
There
have been no other changes to the Ameren Companies’ credit ratings since the
Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended
December 31, 2005.
Any
adverse change in the Ameren Companies’ credit ratings may reduce access to
capital. It may also increase the cost of borrowing and fuel and power supply,
among other things, resulting in a negative impact on earnings. For example,
if
at June 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 for certain trade obligations amounting
to $129
million, $15 million, $6 million, $6 million, $15 million, $15 million, or
$70
million, respectively. In addition, the cost of borrowing under our credit
facilities can increase or decrease with credit ratings. 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:
· |
On
July 19, 2006 and July 21, 2006, UE’s, CIPS’ and IP’s service territories
were hit by severe storms, which included tornados, that resulted
in the
loss of power to approximately 700,000 customers combined. Through
the
dedication of a work force of 5,200, including our employees, contractors
and utility workers from 13 states, we restored service to all
of our
customers within nine days. The full financial impact of these
storms has
not yet been determined, but UE, CIPS and IP have incurred unanticipated
costs and the loss of electric margins as a result of these devastating
storms.
|
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
July 2006, UE, CIPS and Genco mutually consented to terminate the
JDA on
December 31, 2006. Upon termination of the JDA, Genco will no longer
receive the margins on sales that were supplied with power from
UE.
However, Genco will still have access to its own generation and
expects to
be able to sell this power at higher average prices than this power
was
sold for in 2005 because of the expiration of its power supply
contract
with CIPS and the expiration of contracts to supply other wholesale
and
retail customers on or before December 31, 2006. 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.
Termination of the JDA will require acceptance by FERC. See Note 2 -
Rate and Regulatory Matters and Note 7 -
|
68
Related
Party Transactions to our financial statements
under Part I, Item 1, of this report for a further discussion of the
JDA.
· |
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 appeal. Power supplied by Genco and
AERG to
CIPS and CILCO, respectively, have 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. Genco currently
expects to generate approximately 17.5 million megawatthours of
power in
2007. By 2007, only 5.2 million megawatthours of power covered
by
wholesale and retail electric power supply agreements that were
in effect
in 2005 will remain outstanding. 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 compared to 5.9 million megawatthours of power that
was
generated in 2005 at an average cost of approximately $15 per
megawatthour. 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.
|
· |
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. The amount of the increase will depend on outcomes
for CIPS’,
CILCO’s and IP’s pending electric delivery services revenue increase
requests to the ICC and power supply costs that result from the
proposed
Illinois power procurement auction, among other
things.
|
· |
Certain
Illinois legislators, the Illinois attorney general, the Illinois
governor, and other parties have sought and continue to seek various
methods, including rate freeze legislation, to block the power
procurement
auction and/or the recovery of related costs for power supply resulting
from the auction through rates to customers. Any decision or action
that
impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power
costs from their electric customers in a timely manner could result
in
material adverse consequences for these companies and for Ameren.
CIPS,
CILCO and IP are willing to work with stakeholders to ease the
burden of
higher energy prices on residential customers through a rate increase
phase-in plan, as long as such plan allows for the full and timely
recovery of costs and does not adversely impact credit ratings.
In March
2006, legislation was introduced in the Illinois House of Representatives
that would allow the 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.
In June
2006, CIPS, CILCO and IP filed a rate increase phase-in and revenue
securitization plan with the ICC that was based on this proposed
legislation that would relate to the deferral of power supply costs
for
2007 and 2008.
|
· |
The
Ameren Illinois utilities filed proposed new tariffs with the ICC
in
December 2005 that would increase annual revenues from electric
delivery
services, effective January 2, 2007, by $156 million (CIPS - $14
million,
CILCO - $33 million, IP - $109 million) per year commencing in
2007 and an
additional $46 million (CILCO - $10 million, IP - $36 million)
per year
commencing in 2008. 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 April 2006, the Illinois
attorney general and CUB recommended net increases in revenues
for
electric delivery services of $71 million for the Ameren Illinois
utilities (CIPS - $7 million decrease, CILCO - $19 million increase
and IP
- $59 million increase). In subsequent testimony, the Illinois
attorney
general accepted certain of the Ameren Illinois utilities’
positions increasing the estimated aggregate recommended revenue
increase to $100 million. Other parties also made recommendations in
the case. The ICC has until November 2006 to render a decision
in these
rate cases. See Note 2 - Rate and Regulatory Matters to our financial
statements under Part I, Item 1, of this
report.
|
· |
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.
|
· |
We
expect continued economic growth in our service territory to benefit
energy demand in 2006 and beyond, but higher energy prices could
result in
reduced demand from consumers.
|
· |
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
|
69
wholesale
and interchange markets and influence the cost
of power we purchase in the interchange markets.
· |
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 May
2005, the joint Burlington Northern-Union Pacific rail line in
the Powder
River Basin suffered two derailments due to unstable track conditions.
As
a result, the Federal Rail Administration placed slow orders, or
speed
restrictions, on sections of the line until the track could be
made safe.
Because of the railroad delivery problems, UE, Genco and CILCO
received
only about 90% to 95% of scheduled deliveries of Powder River Basin
coal
in 2005. The impact of the coal delivery issues on inventory levels
was
exacerbated by warm summer weather and high power prices, which
caused UE,
Genco and CILCO plants to run more and to burn record amounts of
coal.
Maintenance on the rail lines into the Powder River Basin is continuing
in
2006, but is expected to have less of an impact on deliveries than
in
2005. Further 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 an additional 15% to 20% in 2007.
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 for information about
the
percentage of fuel and transportation requirements that are price-hedged
for 2006 through 2010.
|
· |
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. Detailed
rules for the fuel and purchased power cost recovery mechanism
are
expected to be effective in the second half of 2006. We are unable
to
predict when rules implementing the environmental cost recovery
mechanism
will be formally proposed and adopted. As part of its electric
rate case
filing in July 2006, UE requested the use of the fuel, purchased
power,
and environmental cost recovery
mechanisms.
|
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 incident
is
being investigated by FERC and state authorities. The facility
will remain
out of service until reviews by FERC and 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 most, if not all, of 2008. 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 will be covered by insurance. UE expects the total cost
for
damage and liabilities resulting from the Taum Sauk incident to
range from
$63 million to $83 million. As of June 30, 2006, UE had paid $27
million
and accrued a $36 million liability, while expensing $11 million,
and
recording a $52 million receivable due 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 or federal
authorities. Until the reviews conducted by state and
federal 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. During an outage, which occurs every 18 months, maintenance
and purchased power costs increase, and the amount of
|
70
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.
|
· |
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.
|
· |
In
March 2006, UE completed the purchase of three gas-fired CT facilities
with a capacity of nearly 1,500 megawatts in transactions valued
at $292
million. The purchase of these facilities is designed to meet UE’s
increased generating capacity needs and to provide additional flexibility
in determining future baseload generating capacity additions. 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 2015. 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. On July 7, 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. Genco will no longer receive the margins on sales
that
it made, which were supplied with power from UE. Termination of
the JDA
will require acceptance by FERC. Ameren’s and UE’s earnings will be
affected by the termination of the JDA when UE’s rates are adjusted by the
MoPSC. See Risk Factors under Part II, Item 1A and 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, 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
· |
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
|
71
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 June 30, 2006:
Interest
Expense
|
Net
Income(a)
|
||||
Ameren
|
$
|
13
|
$
|
(8)
|
|
UE
|
8
|
(5)
|
|||
CIPS
|
(b)
|
|
(b)
|
||
Genco
|
3
|
(2)
|
|||
CILCORP
|
2
|
(1)
|
|||
CILCO
|
1
|
(1)
|
|||
IP
|
4
|
(2)
|
(a) Calculations
are based on an effective tax rate of 38%.
(b) Less
than
$1 million.
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 June 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 June 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
72
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 $27 million at June 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
currently does not expect to hedge for price risk a significant portion of
its
available megawatthours. Genco and AERG may participate 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 its past practice. Ultimately, Genco and AERG will
seek to
hedge for price risk the majority of 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 a framework for CIPS, CILCO and IP to procure power for use
by
their customers in 2007 through a September 2006 auction. The approved framework
also allows for full cost recovery of power through a rate mechanism. 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 and purchased
power 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.
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%
|
|
95%
|
|
58%
|
|||
Coal
transportation
|
100
|
95
|
60
|
|||||
Nuclear
fuel
|
100
|
100
|
70
|
|||||
Natural
gas for generation
|
66
|
12
|
2
|
|||||
Natural
gas for distribution(a)
|
(a)
|
|
33
|
7
|
||||
UE:
|
|
|
||||||
Coal
|
100%
|
|
95%
|
|
54%
|
|||
Coal
transportation
|
100
|
99
|
79
|
|||||
Nuclear
fuel
|
100
|
100
|
70
|
|||||
Natural
gas for generation
|
43
|
5
|
1
|
|||||
Natural
gas for distribution(a)
|
(a)
|
|
22
|
5
|
||||
CIPS:
|
|
|||||||
Natural
gas for distribution(a)
|
(a)
|
|
40%
|
|
15%
|
|||
Purchased
power(b)
|
100
|
-
|
-
|
|||||
Genco:
|
||||||||
Coal
|
100%
|
|
92%
|
|
69%
|
|||
Coal
transportation
|
100
|
95
|
39
|
|||||
Natural
gas for generation
|
100
|
12
|
2
|
|||||
CILCORP/CILCO:
|
||||||||
Coal
|
100%
|
|
97%
|
|
56%
|
|||
Coal
transportation
|
100
|
69
|
44
|
|||||
Natural
gas for distribution(a)
|
(a)
|
|
37
|
6
|
||||
Purchased
power(b)
|
100
|
-
|
-
|
73
2006
|
2007
|
2008
-
2010
|
IP:
|
|
|||||||
Natural
gas for distribution(a)
|
(a)
|
|
30%
|
|
5%
|
|||
Purchased
power(b)
|
90
|
-
|
-
|
(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) |
Beginning
in 2007, CIPS, CILCO and IP are expected to purchase all electric
capacity
and energy through a power procurement auction process approved
by the
ICC. See Note 2 - Rate and Regulatory Matters 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
|
$
|
8
|
$
|
(5)
|
|
$
|
10
|
$
|
(6)
|
||
UE
|
5
|
(3)
|
|
3
|
(2)
|
||||||
Genco
|
2
|
(1)
|
|
4
|
(2)
|
||||||
CILCORP/CILCO
|
1
|
(1)
|
|
2
|
(1)
|
(a) |
Calculations
are based on an effective tax rate of
38%.
|
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.
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 six months
ended June 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 four
years.
Ameren(a)
|
UE
|
CIPS
|
Genco
|
CILCORP/
CILCO
|
IP
|
||||||||||||||
Three
Months
|
|||||||||||||||||||
Fair
value of contracts at beginning of period, net
|
$
|
30
|
$
|
(3)
|
|
$
|
6
|
$
|
-
|
$
|
24
|
$
|
2
|
||||||
Contracts
realized or otherwise settled during the period
|
(14)
|
|
(2)
|
|
(2)
|
|
1
|
(5)
|
|
(1)
|
|
||||||||
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
|
27
|
3
|
-
|
-
|
(1)
|
|
1
|
||||||||||||
Fair
value of contracts outstanding at end of period, net
|
$
|
43
|
$
|
(2)
|
|
$
|
4
|
$
|
1
|
$
|
18
|
$
|
2
|
||||||
Six
Months
|
|
|
|
|
|
||||||||||||||
Fair
value of contracts at beginning of period, net
|
$
|
69
|
$
|
(5)
|
|
$
|
12
|
$
|
-
|
$
|
50
|
$
|
(2)
|
|
|||||
Contracts
realized or otherwise settled during the period
|
(26)
|
|
(4)
|
|
(5)
|
|
1
|
(9)
|
|
(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
|
(1)
|
|
6
|
(3)
|
|
-
|
(23)
|
|
6
|
||||||||||
Fair
value of contracts outstanding at end of period, net
|
$
|
43
|
$
|
(2)
|
|
$
|
4
|
$
|
1
|
$
|
18
|
$
|
2
|
(a) |
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
74
ITEM
4. CONTROLS AND PROCEDURES.
(a) |
Evaluation
of Disclosure Controls and
Procedures
|
As
of
June 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.
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 certain Ameren Companies are allowed to charge
in
Missouri and Illinois are largely set through 2006 and are currently the
subject
of various rate case proceedings. The outcome of these rate case proceedings,
along with other actions of lawmakers and regulators that can significantly
adversely affect our prospective earnings, liquidity, or business activities,
are largely outside our control.
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 impact on our businesses including our results
of
operations, financial position, or liquidity.
As
a part
of the settlement of UE’s Missouri electric rate case in August 2002, UE was
subject to a rate moratorium that prohibited changes in its electric rates
in
Missouri before July 1, 2006. Furthermore, as part of the settlement of
UE’s
Missouri gas rate case, which was approved by the MoPSC in January 2004, UE
agreed to make no changes in its gas delivery rates prior to July 1, 2006,
with certain exceptions. With the expiration of these electric and gas
rate
moratoriums, UE filed in July 2006 requests with the MoPSC for an increase
in
electric rates of $361 million and an $11 million increase in natural gas
delivery rates. The MoPSC staff and other stakeholders will review UE’s rate
adjustment requests and, after their analyses, may also make recommendations
as
to electric
75
and
gas
rate adjustments. A decision from the MoPSC is expected no later than June
2007.
The
ICC
order approving Ameren’s acquisition of IP prohibited IP from filing for any
increase in gas delivery rates effective before January 1, 2007, beyond IP’s
then-pending request for a gas delivery rate increase. In addition, 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. This Illinois legislation also requires that 50%
of the
earnings from each respective jurisdiction in excess of certain levels be
refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. 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 and related tariffs. This
approval is subject to a pending court appeal. In addition, certain Illinois
legislators, the Illinois attorney general, the Illinois governor, and other
parties have sought and continue to seek to block the power procurement auction
and/or the recovery, through rates to customers, of related costs for power
supply resulting from the auction. Any decision or action that impairs CIPS’,
CILCO’s and IP’s ability to fully recover purchased power costs from their
electric customers in a timely manner could result in material adverse
consequences for these companies and for Ameren, including a significant
drop in
credit ratings (possibly to below investment-grade status), a loss of access
to
the capital markets, higher borrowing costs, higher power supply costs, an
inability to make timely energy infrastructure investments, impaired customer
service, job losses, and financial insolvency.
The
Illinois legislature held hearings in 2005 and 2006 regarding the framework
for
retail rate determination and power procurement. In February 2006, legislation
was introduced in the Illinois House of Representatives that would extend
the
electric rate freeze in Illinois through 2010. 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 potential significant increases in customer rates for the Ameren Illinois
utilities beginning in 2007. We 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 would not result in further reductions in credit ratings from December
31,
2005 levels. We believe a rate increase phase-in plan, providing for
deferral of costs with certainty of full and timely recovery of any deferred
costs, would require legislation in Illinois. In March 2006, legislation
was
introduced in the Illinois House of Representatives that would allow the
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. Securitization would allow these special purpose
vehicles to issue debt securities and use the proceeds to pay the utilities
immediately upon issuance of the bonds for the deferred power costs for which
the utilities did not receive reimbursement from customers
during a phase-in deferral period. Customers would fund, through dedicated
charges included on their electric bills, a future payment stream that would
be
used to service the securitized debt. In effect, through these charges
utility customers would pay in the future for power used, but not paid for,
during a phase-in deferral period. This approach has the effect of
spreading over the life of the bonds, a period of up to 10 years, the
potentially significant initial electric rate increase for residential customers
that would otherwise be necessary to pay the power procurement costs on a
current basis. If passed, this legislation would assist our Ameren Illinois
utilities in maintaining their financial integrity while allowing them to
recover costs from customers over a longer term. We cannot predict what
actions, if any, the Illinois legislature may ultimately take. In June 2006,
the
Ameren Illinois utilities filed with the ICC a rate increase phase-in and
revenue securitization plan for residential customers similar to the legislation
outlined above that would relate to the deferral of power and supply cost
for
2007 and 2008. Legislation would be needed for this plan to become effective.
In
July 2006, the Illinois attorney general filed a motion with the ICC to dismiss
this plan. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability
to fully recover purchased power costs from their electric customers in a
timely
manner could result in material adverse consequences for these companies
and for
Ameren.
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.
There can be no assurance that Ameren and the Ameren Illinois utilities
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 and
the
Ameren Illinois utilities are considering will be successful.
In
December 2005, the Ameren Illinois utilities filed
proposed new tariffs with the ICC that would increase annual revenues from
electric delivery services, effective January 2, 2007, based on a proposed
residential rate phase-in plan, by $156 million (CIPS - $14 million, CILCO
-
76
$33
million, IP - $109 million) per year commencing in 2007 and an additional
$46
million (CILCO - $10 million, IP - $36 million) per year commencing in 2008.
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 April 2006, the Illinois attorney general recommended increases
in
revenues for electric delivery services aggregating $71 million for the Ameren
Illinois utilities (CIPS - $7 million decrease, CILCO - $19 million increase
and
IP - $59 million increase). In subsequent testimony, the Illinois attorney
general accepted certain of the Ameren Illinois utilities’
positions increasing the estimated aggregate recommended revenue increase
to $100 million. Other parties also made recommendations in the case. The
ICC
has until November 2006 to render a decision in these rate cases.
As
a part
of the settlement of UE’s Missouri electric rate case in 2002, UE made a
commitment to make $2.25 billion to $2.75 billion in critical energy
infrastructure investments from January 1, 2002 through June 30, 2006.
Ameren also committed IP to make between $275 million and $325 million in
energy
infrastructure investments over its first two years of ownership, in conjunction
with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate
moratorium in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that
capital expenditures will not become recoverable in rates and will not earn
a
return until the resolution of the current rate case proceedings for UE,
CIPS,
CILCO and IP. In addition, without appropriate and timely rate relief, any
new
energy infrastructure investment could result in increased financing
requirements for UE, CIPS, CILCO and IP. This could have a material impact
on
our results of operations, financial position, or liquidity.
The
Ameren Companies do not currently have, in either Missouri or Illinois, a
rate
adjustment clause for their electric operations that would allow them to
recover
the costs for purchased power or increased fuel costs from customers. Therefore,
insofar as we have not hedged our fuel and power costs, we are exposed to
changes in fuel and power prices to the extent that fuel for our electric
generating facilities and power to supply customers must be purchased on
the
open market. In its Missouri electric rate case filed in July 2006, UE requested
a fuel and purchased power cost recovery mechanism.
Steps
taken and being considered at the federal and state levels continue to change
the structure of the electric industry and utility regulation. At the federal
level, FERC has been mandating changes in the regulatory framework for
transmission-owning public utilities such as UE, CIPS, CILCO and IP.
Principally
because of rate reductions and moratoriums, increased costs and investments
have
caused decreased returns in Ameren’s utility businesses. Ameren expects many of
its operating expenses to continue to rise and further expects to continue
to
make significant investment in its energy infrastructure, which is the principal
factor underlying its pending rate increase requests with the MoPSC and the
ICC.
We cannot predict the outcome of these proceedings. 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 significant adverse effect on our results
of
operations, financial position, or liquidity.
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
|
|||||||||
April
1 - April 30, 2006
|
1,551
|
$
|
50.47
|
-
|
-
|
||||||||
May
1 - May 31, 2006
|
428
|
49.87
|
-
|
-
|
|||||||||
June
1 - June 30, 2006
|
2,700
|
50.44
|
-
|
-
|
|||||||||
Total
|
4,679
|
$
|
50.40
|
-
|
-
|
(a) |
Included
in April was 1 share of Ameren common stock purchased to satisfy
an
employee’s tax obligation incurred with the vesting of a performance share
unit and share distribution under Ameren’s Long-term Incentive Plan of
1998 upon the employee’s death. Included in May were 428 shares of
Ameren common stock purchased in connection with the satisfaction
of
employee tax obligations incurred by the release of restricted
shares of
Ameren common stock under the Long-term Incentive Plan of 1998. The
remaining 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.
|
77
None
of
the other registrants purchased equity securities reportable under Item 703
of
Regulation S-K during the April 1 to June 30, 2006 period.
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Ameren
At
Ameren’s annual meeting of shareholders held on May 2, 2006, the following
matters were presented to the meeting for a vote and the results of such
voting
are as follows:
Item
(1) Election
of 11 directors (comprising Ameren’s full Board of Directors) to serve until the
next annual meeting of shareholders in 2007.
Name
|
For
|
Withheld
|
Broker
Non-Votes(a)
|
Susan
S. Elliott
|
170,433,601
|
3,399,101
|
-
|
Gayle
P.W. Jackson
|
170,555,732
|
3,276,970
|
-
|
James
C. Johnson
|
170,503,619
|
3,329,083
|
-
|
Richard
A. Liddy
|
169,543,114
|
4,289,588
|
-
|
Gordon
R. Lohman
|
169,700,926
|
4,131,776
|
-
|
Richard
A. Lumpkin
|
169,743,607
|
4,089,095
|
-
|
Charles
W. Mueller
|
170,429,775
|
3,402,927
|
-
|
Douglas
R. Oberhelman
|
169,918,926
|
3,913,776
|
-
|
Gary
L. Rainwater
|
170,153,917
|
3,678,785
|
-
|
Harvey
Saligman
|
169,812,589
|
4,020,113
|
-
|
Patrick
T. Stokes
|
170,012,820
|
3,819,882
|
-
|
(a)
Broker shares included in the quorum but not voting on the item.
Item
(2) Ameren
proposal regarding approval of the 2006 Omnibus Incentive Compensation
Plan.
For
|
Against
|
Abstain
|
Broker
Non-Votes(a)
|
113,160,592
|
11,497,749
|
3,295,718
|
65,213,786
|
(a)
Broker shares included in the quorum but not voting on the item.
Item
(3) Ameren
proposal regarding ratification of the appointment of PricewaterhouseCoopers
LLP
as Ameren’s independent auditors for the fiscal year ending December 31,
2006.
For
|
Against
|
Abstain
|
Broker
Non-Votes(a)
|
167,748,938
|
2,015,561
|
1,822,316
|
21,553,105
|
(a) |
Broker
shares included in the quorum but not voting on the
item.
|
Item
(4) Shareholder
proposal requesting an evaluation of a 20-year extension of UE’s Callaway
nuclear plant operating license.
For
|
Against
|
Abstain
|
Broker
Non-Votes(a)
|
9,084,767
|
106,585,670
|
12,364,615
|
65,132,792
|
(a) |
Broker
shares included in the quorum but not voting on the
item.
|
UE
At
UE’s
annual meeting of shareholders held on May 2, 2006, the following individuals
(comprising UE’s full Board of Directors) were elected to serve until the next
annual meeting of shareholders in 2007: Warner L. Baxter, Daniel F. Cole,
Richard J. Mark, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and
David
A. Whiteley. Each individual received 102,123,834 votes for election and
no
withheld votes or broker non-votes.
CIPS
At
CIPS’
annual meeting of shareholders held on May 2, 2006, the following individuals
(comprising CIPS’ full Board of Directors) were elected to serve until the next
annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel,
Daniel
F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David
A.
Whiteley. Each individual received 25,452,373 votes for election and no withheld
votes or broker non-votes.
78
CILCO
At
CILCO’s annual meeting of shareholders held on May 2, 2006, the following
individuals (comprising CILCO’s full Board of Directors) were elected to serve
until the next annual meeting of shareholders in 2007: Warner L. Baxter,
Scott
A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R.
Voss and David A. Whiteley. Each individual received 13,563,871 votes for
election and no withheld votes or broker non-votes.
IP
At
IP’s
annual meeting of shareholders held on May 2, 2006, the following individuals
(comprising IP’s full Board of Directors) were elected to serve until the next
annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel,
Daniel
F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David
A.
Whiteley. Each individual received 23,662,924 votes for election and no withheld
votes or broker non-votes.
GENCO
and CILCORP
The
information called for by this item is omitted in reliance on General
Instruction H(1)(a) and (b) of Form 10-Q.
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
|
Material
Contracts
|
||
10.1
|
Ameren
Companies
|
June
9, 2006 Revised Schedule 1 to Amended and Restated Ameren Corporation
Change
of Control Severance Plan previously filed as Exhibit 10.5 to
February 16,
2006
Form 8-K
|
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
|
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
|
79
Exhibit
Designation
|
Registrant(s)
|
Nature
of Exhibit
|
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
|
80
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)
81
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:
August 9, 2006
82