Ameren Illinois Co - Quarter Report: 2007 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, 2007
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
|
||
(888)
789-2477
|
||
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 requirements 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, 2007, was as
follows:
Ameren
Corporation
|
Common
stock, $.01 par value per share – 207,601,632
|
Union
Electric Company
|
Common
stock, $5 par value per share, held by Ameren
Corporation
(parent company of the registrant) – 102,123,834
|
Central
Illinois Public Service Company
|
Common
stock, no par value, held by Ameren
Corporation
(parent company of the registrant) – 25,452,373
|
Ameren
Energy Generating Company
|
Common
stock, no par value, held by Ameren Energy
Development
Company (parent company of the
registrant
and indirect subsidiary of Ameren
Corporation)
– 2,000
|
CILCORP
Inc.
|
Common
stock, no par value, held by Ameren
Corporation
(parent company of the registrant) – 1,000
|
Central
Illinois Light Company
|
Common
stock, no par value, held by CILCORP Inc.
(parent
company of the registrant and subsidiary of
Ameren
Corporation) – 13,563,871
|
Illinois
Power Company
|
Common
stock, no par value, held by Ameren
Corporation
(parent company of the registrant) –
23,000,000
|
OMISSION
OF CERTAIN INFORMATION
Ameren
Energy Generating Company and CILCORP Inc. meet the conditions set forth
in
General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing
this
form with the reduced disclosure format allowed under that General
Instruction.
This
combined Form 10-Q is separately
filed by Ameren Corporation, Union Electric Company, Central Illinois Public
Service Company, Ameren Energy Generating Company, CILCORP Inc., Central
Illinois Light Company, and Illinois Power Company. Each registrant hereto
is
filing on its own behalf all of the information contained in this quarterly
report that relates to such registrant. Each registrant hereto is not filing
any
information that does not relate to such registrant, and therefore makes
no
representation as to any such information.
TABLE
OF CONTENTS
Page
|
|
Glossary
of Terms and
Abbreviations .............................................................................................................................................................................................................................................
|
5
|
Forward-looking
Statements...............................................................................................................................................................................................................................................................
|
6
|
PART
I Financial
Information
|
|
Item
1. Financial Statements
(Unaudited)
|
|
Ameren
Corporation
|
|
Consolidated
Statement of
Income.....................................................................................................................................................................................................................
|
8
|
Consolidated
Balance
Sheet................................................................................................................................................................................................................................
|
9
|
Consolidated
Statement of Cash
Flows.............................................................................................................................................................................................................
|
10
|
Union
Electric Company
|
|
Consolidated
Statement of
Income.....................................................................................................................................................................................................................
|
11
|
Consolidated
Balance
Sheet................................................................................................................................................................................................................................
|
12
|
Consolidated
Statement of Cash
Flows.............................................................................................................................................................................................................
|
13
|
Central
Illinois Public Service Company
|
|
Statement
of
Income.............................................................................................................................................................................................................................................
|
14
|
Balance
Sheet.........................................................................................................................................................................................................................................................
|
15
|
Statement
of Cash
Flows......................................................................................................................................................................................................................................
|
16
|
Ameren
Energy Generating Company
|
|
Consolidated
Statement of
Income.....................................................................................................................................................................................................................
|
17
|
Consolidated
Balance
Sheet................................................................................................................................................................................................................................
|
18
|
Consolidated
Statement of Cash
Flows.............................................................................................................................................................................................................
|
19
|
CILCORP
Inc.
|
|
Consolidated
Statement of
Income.....................................................................................................................................................................................................................
|
20
|
Consolidated
Balance
Sheet................................................................................................................................................................................................................................
|
21
|
Consolidated
Statement of Cash
Flows.............................................................................................................................................................................................................
|
22
|
Central
Illinois Light Company
|
|
Consolidated
Statement of
Income.....................................................................................................................................................................................................................
|
23
|
Consolidated
Balance
Sheet................................................................................................................................................................................................................................
|
24
|
Consolidated
Statement of Cash
Flows.............................................................................................................................................................................................................
|
25
|
Illinois
Power Company
|
|
Consolidated
Statement of
Income.....................................................................................................................................................................................................................
|
26
|
Consolidated
Balance
Sheet................................................................................................................................................................................................................................
|
27
|
Consolidated
Statement of Cash
Flows.............................................................................................................................................................................................................
|
28
|
Combined
Notes to Financial
Statements..................................................................................................................................................................................................................
|
29
|
Item
2. Management’s Discussion and
Analysis of Financial Condition and Results of
Operations.............................................................................................................................
|
57
|
Item
3. Quantitative and Qualitative
Disclosures About Market
Risk..................................................................................................................................................................................
|
79
|
Item
4. Controls and
Procedures.................................................................................................................................................................................................................................................
|
83
|
PART
II Other Information
|
|
Item
1. Legal
Proceedings............................................................................................................................................................................................................................................................
|
84
|
Item
1A. Risk
Factors.......................................................................................................................................................................................................................................................................
|
84
|
Item
2. Unregistered Sales of
Equity Securities and Use of
Proceeds..................................................................................................................................................................................
|
86
|
Item
4. Submission of Matters to a
Vote of Security
Holders................................................................................................................................................................................................
|
87
|
Item
6.
Exhibits...............................................................................................................................................................................................................................................................................
|
88
|
Signatures..............................................................................................................................................................................................................................................................................................
|
90
|
This
Form 10-Q contains
“forward-looking” statements within the meaning of Section 21E of the Securities
Exchange Act of 1934, as amended. Forward-looking statements are all statements
other than statements of historical fact, including those statements that
are
identified by the use of the words “anticipates,” “estimates,” “expects,”
“intends,” “plans,” “predicts,” “projects,” and similar expressions.
Forward-looking statements should be read with the cautionary statements
and
important factors included on page 6 of this Form 10-Q under the heading
“Forward-looking Statements.”
4
GLOSSARY
OF TERMS AND ABBREVIATIONS
We
use
the words “our,” “we” or “us” with respect to certain information that relates
to all Ameren Companies, as defined below. When appropriate, subsidiaries
of
Ameren are named specifically as we discuss their various business
activities.
AERG
– AmerenEnergy Resources Generating Company, a CILCO subsidiary
that operates a non-rate-regulated electric generation business in
Illinois.
AFS
– Ameren Energy Fuels and Services Company, a Development Company
subsidiary that procures fuel and natural gas and manages the related risks
for
the Ameren Companies.
Ameren
– Ameren Corporation and its subsidiaries on a consolidated
basis.
In references to financing activities, acquisition activities, or liquidity
arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren
Companies – The individual registrants within the Ameren
consolidated group.
Ameren
Energy – Ameren Energy, Inc., an Ameren Corporation subsidiary
that is a power marketing and risk management agent for UE.
Ameren
Illinois Utilities– CIPS, IP and the rate-regulated electric and
gas utility operations of CILCO.
Ameren
Services – Ameren Services Company,
an Ameren Corporation subsidiary that provides support services to Ameren
and
its subsidiaries.
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 and natural gas transmission and distribution
business and a non-rate-regulated electric generation business through
AERG, 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.
CIPSCO
– CIPSCO Inc., the former parent
of
CIPS.
CT
– Combustion turbine electric generation equipment used primarily
for peaking capacity.
CUB
– Citizens Utility Board.
Development
Company – Ameren Energy Development Company, which is a Resources
Company subsidiary, and parent of Genco, Marketing Company and AFS.
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
non-rate-regulated electric generation facilities and FERC-regulated
transmission facilities in Illinois. The remaining 20% is owned by Kentucky
Utilities Company.
ELPC
– Environmental Law and Policy Center.
EPA
– Environmental Protection Agency, a U.S. government
agency.
Exchange
Act – Securities Exchange Act of 1934, as amended.
FASB
– Financial Accounting Standards Board, a rulemaking organization
that establishes financial accounting and reporting standards in the United
States.
FERC
– The Federal Energy Regulatory Commission, a U.S. government
agency.
FIN
– FASB Interpretation. A FIN statement is an explanation intended
to clarify accounting pronouncements previously issued by the FASB.
Fitch
– Fitch Ratings, a credit rating agency.
Form
10-K – The combined Annual Report
on Form 10-K for the year ended December 31, 2006, filed by the Ameren
Companies
with the SEC.
FSP–
FASB Staff Position, which provides application guidance on FASB
literature.
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 the rate-regulated operations of CIPS,
CILCO and
IP.
Illinois
Customer Choice Law – Illinois Electric Service Customer Choice
and Rate Relief Law of 1997, which provided for electric utility restructuring
and introduced competition into the retail supply of electric energy in
Illinois.
Illinois
EPA– Illinois Environmental Protection Agency, a state government
agency.
Illinois
Regulated – A financial reporting segment consisting of the
regulated electric and gas transmission and distribution businesses of
CIPS,
CILCO and IP.
IP
– Illinois Power Company, an Ameren
Corporation subsidiary. IP operates a rate-regulated electric and natural
5
gas
transmission and distribution business in Illinois as AmerenIP.
IPA–
Illinois Power Agency, a state government agency that would have broad
authority
to assist in the procurement of electric power for residential and
nonresidential customers beginning in June 2009 pending enactment of legislation
by the Illinois governor.
IP
LLC– Illinois Power Securitization Limited Liability Company,
which is a special-purpose Delaware limited-liability company. Under FIN
46R,
Consolidation of Variable-interest Entities, IP LLC was no longer consolidated
within IP’s financial statements as of December 31, 2003.
IP
SPT– Illinois Power Special Purpose Trust, which was created as
a
subsidiary of IP LLC 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 dispatched electric generation prior to its
termination on December 31, 2006.
Kilowatthour– A
measure of electricity consumption equivalent to the use of 1,000 watts
of power
over a period of one hour.
Marketing
Company – Ameren Energy Marketing
Company, a Development Company subsidiary that markets power for Genco,
AERG and
EEI.
Medina
Valley– AmerenEnergy Medina Valley
Cogen (No. 4) LLC and its subsidiaries, 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 uses market-based pricing, incorporating transmission congestion and
line
losses, to compensate market participants for power.
Missouri
Regulated – A financial reporting segment consisting of all the
operations of UE’s business, except for UE’s 40% interest in EEI and other
non-rate-regulated activities.
Money
pool – Borrowing agreements among
Ameren and its subsidiaries to coordinate and provide for certain short-term
cash and working capital requirements. Separate money pools are maintained
between rate-regulated and non-rate-regulated businesses. These are referred
to
as the utility money pool and the non-state-regulated subsidiary money
pool,
respectively.
Moody’s
– Moody’s Investors Service Inc., a
credit rating agency.
MoPSC
– Missouri Public Service Commission, a state agency that
regulates the Missouri utility business and operations of UE.
Non-rate-regulated
Generation – A financial reporting segment consisting of the
operations or activities of Genco, CILCORP holding company, AERG, EEI and
Marketing Company.
NOx – Nitrogen
oxide.
NRC
– Nuclear Regulatory Commission, a U.S. government
agency.
NYMEX
– New York Mercantile Exchange.
OCI
– Other comprehensive income (loss)
as defined by GAAP.
PGA
– Purchased Gas Adjustment tariffs, which allow the passing
through of the actual cost of natural gas to utility customers.
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, 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 the
Illinois
Customer Choice Law. 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.
Since
the application of FIN 46R, IP does not consolidate IP SPT. Therefore,
the
obligation to IP SPT appears on IP’s balance sheet.
TVA–
Tennessee Valley Authority, a public power authority.
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
6
the
expected results will be achieved. These statements include (without limitation)
statements as to future expectations, beliefs, plans, strategies, objectives,
events, conditions, and financial performance. In connection with the “safe
harbor” provisions of the Private Securities Litigation Reform Act of 1995,
we are providing this cautionary statement to identify important factors
that
could cause actual results to differ materially from those anticipated.
The
following factors, in addition to those discussed under Risk Factors and
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 failure of the Illinois
governor to
enact legislation implementing the comprehensive rate relief
programs and
agreement, the enactment of alternative legislation rolling back
and
freezing electric rates at 2006 levls or similar actions that
impair the
full and timely recovery of costs in Illinois, or the enactment
of
alternative legislation taxing electric generators in
Illinois;
|
·
|
the
impact of the termination of the
JDA;
|
·
|
changes
in laws and other governmental actions, including monetary and
fiscal
policies;
|
·
|
the
effects of increased competition in the future due to, among
other things,
deregulation of certain aspects of our business at both the state
and
federal levels, and the implementation of deregulation, such
as occurred
when the electric rate freeze and power supply contracts expired
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 the plant’s future operation;
|
·
|
recoverability
through insurance of costs associated with UE’s Taum Sauk pumped-storage
hydroelectric plant incident;
|
·
|
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,
including those related to greenhouse gases, will be introduced
over time,
which could have a negative financial
effect;
|
·
|
labor
disputes, future wage and employee benefits costs, including
changes in
returns on benefit plan assets;
|
·
|
the
inability of our counterparties and affiliates to meet their
obligations
with respect to contracts and financial
instruments;
|
·
|
the
cost and availability of transmission capacity for the energy
generated by
the Ameren Companies’ facilities or required to satisfy energy sales made
by the Ameren Companies;
|
·
|
legal
and administrative proceedings; and
|
·
|
acts
of sabotage, war, terrorism or intentionally disruptive
acts.
|
Given
these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to update or revise publicly
any
forward-looking statements to reflect new information or future
events.
7
PART
I. FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS.
AMEREN
CORPORATION
|
||||||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
||||||||||||||||
(Unaudited)
(In millions, except per share amounts)
|
||||||||||||||||
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
|||||||||||||||
2007
|
2006
|
2007
|
2006
|
|||||||||||||
Operating
Revenues:
|
||||||||||||||||
Electric
|
$ |
1,514
|
$ |
1,378
|
$ |
2,972
|
$ |
2,589
|
||||||||
Gas
|
209
|
172
|
770
|
761
|
||||||||||||
Total
operating revenues
|
1,723
|
1,550
|
3,742
|
3,350
|
||||||||||||
Operating
Expenses:
|
||||||||||||||||
Fuel
|
263
|
247
|
526
|
499
|
||||||||||||
Purchased
power
|
314
|
277
|
687
|
550
|
||||||||||||
Gas
purchased for resale
|
133
|
104
|
554
|
557
|
||||||||||||
Other
operations and maintenance
|
426
|
394
|
822
|
746
|
||||||||||||
Depreciation
and amortization
|
169
|
162
|
345
|
323
|
||||||||||||
Taxes
other than income taxes
|
96
|
90
|
198
|
203
|
||||||||||||
Total
operating expenses
|
1,401
|
1,274
|
3,132
|
2,878
|
||||||||||||
Operating
Income
|
322
|
276
|
610
|
472
|
||||||||||||
Other
Income and Expenses:
|
||||||||||||||||
Miscellaneous
income
|
20
|
11
|
34
|
16
|
||||||||||||
Miscellaneous
expense
|
(4 | ) | (1 | ) | (4 | ) | (1 | ) | ||||||||
Total
other income
|
16
|
10
|
30
|
15
|
||||||||||||
Interest
Charges
|
108
|
87
|
206
|
164
|
||||||||||||
Income
Before Income Taxes, Minority Interest
|
||||||||||||||||
and
Preferred Dividends of Subsidiaries
|
230
|
199
|
434
|
323
|
||||||||||||
Income
Taxes
|
78
|
68
|
149
|
112
|
||||||||||||
Income
Before Minority Interest and Preferred
|
||||||||||||||||
Dividends
of Subsidiaries
|
152
|
131
|
285
|
211
|
||||||||||||
Minority
Interest and Preferred Dividends of Subsidiaries
|
9
|
8
|
19
|
18
|
||||||||||||
Net
Income
|
$ |
143
|
$ |
123
|
$ |
266
|
$ |
193
|
||||||||
Earnings
per Common Share – Basic and Diluted
|
$ |
0.69
|
$ |
0.60
|
$ |
1.29
|
$ |
0.94
|
||||||||
Dividends
per Common Share
|
$ |
0.635
|
$ |
0.635
|
$ |
1.270
|
$ |
1.270
|
||||||||
Average
Common Shares Outstanding
|
207.1
|
205.4
|
206.9
|
205.1
|
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,
|
||||||
2007
|
2006
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$ |
687
|
$ |
137
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $31 and $11, respectively)
|
562
|
418
|
|||||
Unbilled
revenue
|
304
|
309
|
|||||
Miscellaneous
accounts and notes receivable
|
222
|
160
|
|||||
Materials
and supplies
|
612
|
647
|
|||||
Other
current assets
|
178
|
203
|
|||||
Total
current assets
|
2,565
|
1,874
|
|||||
Property
and Plant, Net
|
14,538
|
14,286
|
|||||
Investments
and Other Assets:
|
|||||||
Investments
in leveraged leases
|
13
|
13
|
|||||
Nuclear
decommissioning trust fund
|
301
|
285
|
|||||
Goodwill
|
831
|
831
|
|||||
Intangible
assets
|
206
|
217
|
|||||
Other
assets
|
730
|
641
|
|||||
Regulatory
assets
|
1,347
|
1,431
|
|||||
Total
investments and other assets
|
3,428
|
3,418
|
|||||
TOTAL
ASSETS
|
$ |
20,531
|
$ |
19,578
|
|||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt
|
$ |
203
|
$ |
456
|
|||
Short-term
debt
|
1,619
|
612
|
|||||
Accounts
and wages payable
|
455
|
671
|
|||||
Taxes
accrued
|
120
|
58
|
|||||
Other
current liabilities
|
423
|
405
|
|||||
Total
current liabilities
|
2,820
|
2,202
|
|||||
Long-term
Debt, Net
|
5,511
|
5,285
|
|||||
Preferred
Stock of Subsidiary Subject to Mandatory
Redemption
|
18
|
18
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
2,039
|
2,144
|
|||||
Accumulated
deferred investment tax credits
|
113
|
118
|
|||||
Regulatory
liabilities
|
1,216
|
1,234
|
|||||
Asset
retirement obligations
|
564
|
549
|
|||||
Accrued
pension and other postretirement benefits
|
1,040
|
1,065
|
|||||
Other
deferred credits and liabilities
|
378
|
169
|
|||||
Total
deferred credits and other liabilities
|
5,350
|
5,279
|
|||||
Preferred
Stock of Subsidiaries Not Subject to Mandatory
Redemption
|
195
|
195
|
|||||
Minority
Interest in Consolidated Subsidiaries
|
19
|
16
|
|||||
Commitments
and Contingencies (Notes 2, 8, and 9)
|
|||||||
Stockholders'
Equity:
|
|||||||
Common
stock, $.01 par value, 400.0 shares authorized –
|
|||||||
shares
outstanding of 207.0 and 206.6, respectively
|
2
|
2
|
|||||
Other
paid-in capital, principally premium on common stock
|
4,551
|
4,495
|
|||||
Retained
earnings
|
2,023
|
2,024
|
|||||
Accumulated
other comprehensive income
|
42
|
62
|
|||||
Total
stockholders’ equity
|
6,618
|
6,583
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$ |
20,531
|
$ |
19,578
|
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,
|
|||||||
2007
|
2006
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$ |
266
|
$ |
193
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Gain
on sales of emission allowances
|
(2 | ) |
-
|
||||
Depreciation
and amortization
|
357
|
340
|
|||||
Amortization
of nuclear fuel
|
15
|
16
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
10
|
7
|
|||||
Deferred
income taxes and investment tax credits, net
|
(8 | ) | (19 | ) | |||
Loss
on sale of noncore properties
|
-
|
4
|
|||||
Minority
interest
|
13
|
12
|
|||||
Other
|
7
|
1
|
|||||
Changes
in assets and liabilities:
|
|||||||
Receivables
|
(195 | ) |
168
|
||||
Materials
and supplies
|
35
|
25
|
|||||
Accounts
and wages payable
|
(62 | ) | (214 | ) | |||
Taxes
accrued
|
59
|
(33 | ) | ||||
Assets,
other
|
(69 | ) |
63
|
||||
Liabilities,
other
|
67
|
10
|
|||||
Pension
and other postretirement benefit obligations
|
50
|
46
|
|||||
Net
cash provided by operating activities
|
543
|
619
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(715 | ) | (449 | ) | |||
CT
acquisitions
|
-
|
(292 | ) | ||||
Nuclear
fuel expenditures
|
(24 | ) | (25 | ) | |||
Proceeds
from sale of noncore properties
|
-
|
11
|
|||||
Purchases
of securities – nuclear decommissioning trust fund
|
(75 | ) | (53 | ) | |||
Sales
of securities – nuclear decommissioning trust fund
|
65
|
48
|
|||||
Purchases
of emission allowances
|
(9 | ) | (38 | ) | |||
Sales
of emission allowances
|
3
|
4
|
|||||
Other
|
1
|
(1 | ) | ||||
Net
cash used in investing activities
|
(754 | ) | (795 | ) | |||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
(263 | ) | (260 | ) | |||
Capital
issuance costs
|
(3 | ) | (2 | ) | |||
Short-term
debt, net
|
1,007
|
204
|
|||||
Dividends
paid to minority interest
|
(10 | ) | (14 | ) | |||
Redemptions,
repurchases, and maturities of long-term debt
|
(443 | ) | (86 | ) | |||
Issuances:
|
|||||||
Common
stock
|
48
|
57
|
|||||
Long-term
debt
|
425
|
232
|
|||||
Net
cash provided by financing activities
|
761
|
131
|
|||||
Net
change in cash and cash equivalents
|
550
|
(45 | ) | ||||
Cash
and cash equivalents at beginning of year
|
137
|
96
|
|||||
Cash
and cash equivalents at end of period
|
$ |
687
|
$ |
51
|
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
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
2007
|
2006
|
2007
|
2006
|
|||||||||||||
Operating
Revenues:
|
||||||||||||||||
Electric
- excluding off-system
|
$ |
579
|
$ |
584
|
$ |
1,030
|
$ |
1,013
|
||||||||
Electric
- off-system
|
89
|
103
|
211
|
241
|
||||||||||||
Gas
|
29
|
22
|
105
|
91
|
||||||||||||
Other
|
-
|
1
|
1
|
1
|
||||||||||||
Total
operating revenues
|
697
|
710
|
1,347
|
1,346
|
||||||||||||
Operating
Expenses:
|
||||||||||||||||
Fuel
|
143
|
124
|
268
|
249
|
||||||||||||
Purchased
power
|
29
|
68
|
62
|
135
|
||||||||||||
Gas
purchased for resale
|
15
|
12
|
64
|
56
|
||||||||||||
Other
operations and maintenance
|
222
|
196
|
446
|
367
|
||||||||||||
Depreciation
and amortization
|
84
|
81
|
171
|
161
|
||||||||||||
Taxes
other than income taxes
|
60
|
59
|
117
|
118
|
||||||||||||
Total
operating expenses
|
553
|
540
|
1,128
|
1,086
|
||||||||||||
Operating
Income
|
144
|
170
|
219
|
260
|
||||||||||||
Other
Income and Expenses:
|
||||||||||||||||
Miscellaneous
income
|
12
|
8
|
20
|
12
|
||||||||||||
Miscellaneous
expense
|
(6 | ) | (2 | ) | (8 | ) | (4 | ) | ||||||||
Total
other income
|
6
|
6
|
12
|
8
|
||||||||||||
Interest
Charges
|
51
|
44
|
97
|
80
|
||||||||||||
Income
Before Income Taxes and Equity
|
||||||||||||||||
in
Income of Unconsolidated Investment
|
99
|
132
|
134
|
188
|
||||||||||||
Income
Taxes
|
30
|
50
|
41
|
69
|
||||||||||||
Income
Before Equity in Income
|
||||||||||||||||
of
Unconsolidated Investment
|
69
|
82
|
93
|
119
|
||||||||||||
Equity
in Income of Unconsolidated Investment,
|
||||||||||||||||
Net
of Taxes
|
12
|
10
|
26
|
24
|
||||||||||||
Net
Income
|
81
|
92
|
119
|
143
|
||||||||||||
Preferred
Stock Dividends
|
2
|
2
|
3
|
3
|
||||||||||||
Net
Income Available to Common Stockholder
|
$ |
79
|
$ |
90
|
$ |
116
|
$ |
140
|
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,
|
||||||
2007
|
2006
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$ |
209
|
$ |
1
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $8 and $6, respectively)
|
220
|
145
|
|||||
Unbilled
revenue
|
157
|
120
|
|||||
Miscellaneous
accounts and notes receivable
|
164
|
128
|
|||||
Advances
to money pool
|
12
|
18
|
|||||
Accounts
receivable – affiliates
|
59
|
33
|
|||||
Materials
and supplies
|
267
|
236
|
|||||
Other
current assets
|
56
|
45
|
|||||
Total
current assets
|
1,144
|
726
|
|||||
Property
and Plant, Net
|
8,000
|
7,882
|
|||||
Investments
and Other Assets:
|
|||||||
Nuclear
decommissioning trust fund
|
301
|
285
|
|||||
Intangible
assets
|
58
|
58
|
|||||
Other
assets
|
474
|
526
|
|||||
Regulatory
assets
|
790
|
810
|
|||||
Total
investments and other assets
|
1,623
|
1,679
|
|||||
TOTAL
ASSETS
|
$ |
10,767
|
$ |
10,287
|
|||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt
|
$ |
152
|
$ |
5
|
|||
Short-term
debt
|
426
|
234
|
|||||
Intercompany
note payable – Ameren
|
37
|
77
|
|||||
Accounts
and wages payable
|
159
|
313
|
|||||
Accounts
payable – affiliates
|
114
|
185
|
|||||
Taxes
accrued
|
142
|
66
|
|||||
Other
current liabilities
|
229
|
191
|
|||||
Total
current liabilities
|
1,259
|
1,071
|
|||||
Long-term
Debt, Net
|
3,212
|
2,934
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
1,273
|
1,293
|
|||||
Accumulated
deferred investment tax credits
|
86
|
89
|
|||||
Regulatory
liabilities
|
838
|
827
|
|||||
Asset
retirement obligations
|
504
|
491
|
|||||
Accrued
pension and other postretirement benefits
|
370
|
374
|
|||||
Other
deferred credits and liabilities
|
83
|
55
|
|||||
Total
deferred credits and other liabilities
|
3,154
|
3,129
|
|||||
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
|
739
|
739
|
|||||
Retained
earnings
|
1,775
|
1,783
|
|||||
Accumulated
other comprehensive income
|
4
|
7
|
|||||
Total
stockholders' equity
|
3,142
|
3,153
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$ |
10,767
|
$ |
10,287
|
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,
|
|||||||
2007
|
2006
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$ |
119
|
$ |
143
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
171
|
161
|
|||||
Amortization
of nuclear fuel
|
15
|
16
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
3
|
3
|
|||||
Deferred
income taxes and investment tax credits, net
|
15
|
11
|
|||||
Other
|
-
|
(5 | ) | ||||
Changes
in assets and liabilities:
|
|||||||
Receivables
|
(174 | ) | (15 | ) | |||
Materials
and supplies
|
(31 | ) | (13 | ) | |||
Accounts
and wages payable
|
(136 | ) | (180 | ) | |||
Taxes
accrued
|
76
|
54
|
|||||
Assets,
other
|
55
|
30
|
|||||
Liabilities,
other
|
17
|
35
|
|||||
Pension
and other postretirement obligations
|
15
|
18
|
|||||
Net
cash provided by operating activities
|
145
|
258
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(355 | ) | (222 | ) | |||
CT
acquisitions
|
-
|
(292 | ) | ||||
Nuclear
fuel expenditures
|
(24 | ) | (25 | ) | |||
Changes
in money pool advances
|
6
|
-
|
|||||
Proceeds
from intercompany note receivable – CIPS
|
-
|
67
|
|||||
Purchases
of securities – nuclear decommissioning trust fund
|
(75 | ) | (53 | ) | |||
Sales
of securities – nuclear decommissioning trust fund
|
65
|
48
|
|||||
Sales
of emission allowances
|
2
|
2
|
|||||
Net
cash used in investing activities
|
(381 | ) | (475 | ) | |||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
(127 | ) | (84 | ) | |||
Dividends
on preferred stock
|
(3 | ) | (3 | ) | |||
Capital
issuance costs
|
(3 | ) |
-
|
||||
Short-term
debt, net
|
192
|
284
|
|||||
Intercompany
note payable – Ameren, net
|
(40 | ) |
-
|
||||
Issuances
of long-term debt
|
425
|
-
|
|||||
Capital
contribution from parent
|
-
|
1
|
|||||
Net
cash provided by financing activities
|
444
|
198
|
|||||
Net
change in cash and cash equivalents
|
208
|
(19 | ) | ||||
Cash
and cash equivalents at beginning of year
|
1
|
20
|
|||||
Cash
and cash equivalents at end of period
|
$ |
209
|
$ |
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
|
Six
Months Ended
|
||||||||||||||
June
30,
|
June
30,
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Operating
Revenues:
|
|||||||||||||||
Electric
|
$ |
193
|
$ |
181
|
$ |
404
|
$ |
341
|
|||||||
Gas
|
36
|
30
|
137
|
127
|
|||||||||||
Other
|
-
|
1
|
2
|
1
|
|||||||||||
Total
operating revenues
|
229
|
212
|
543
|
469
|
|||||||||||
Operating
Expenses:
|
|||||||||||||||
Purchased
power
|
127
|
113
|
277
|
230
|
|||||||||||
Gas
purchased for resale
|
21
|
16
|
95
|
88
|
|||||||||||
Other
operations and maintenance
|
41
|
38
|
84
|
76
|
|||||||||||
Depreciation
and amortization
|
16
|
15
|
33
|
31
|
|||||||||||
Taxes
other than income taxes
|
9
|
9
|
18
|
21
|
|||||||||||
Total
operating expenses
|
214
|
191
|
507
|
446
|
|||||||||||
Operating
Income
|
15
|
21
|
36
|
23
|
|||||||||||
Other
Income and Expenses:
|
|||||||||||||||
Miscellaneous
income
|
5
|
4
|
8
|
9
|
|||||||||||
Miscellaneous
expense
|
(1 | ) |
-
|
(1 | ) | (1 | ) | ||||||||
Total
other income
|
4
|
4
|
7
|
8
|
|||||||||||
Interest
Charges
|
10
|
8
|
18
|
15
|
|||||||||||
Income
Before Income Taxes
|
9
|
17
|
25
|
16
|
|||||||||||
Income
Taxes
|
4
|
2
|
9
|
2
|
|||||||||||
Net
Income
|
5
|
15
|
16
|
14
|
|||||||||||
Preferred
Stock Dividends
|
-
|
-
|
1
|
1
|
|||||||||||
Net
Income Available to Common Stockholder
|
$ |
5
|
$ |
15
|
$ |
15
|
$ |
13
|
The
accompanying notes as they relate to CIPS are an integral part of these
consolidated financial statements.
14
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
|
|||||||
BALANCE
SHEET
|
|||||||
(Unaudited)
(In millions)
|
|||||||
June
30,
|
December
31,
|
||||||
2007
|
2006
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$ |
148
|
$ |
6
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $8 and $2, respectively)
|
65
|
55
|
|||||
Unbilled
revenue
|
32
|
43
|
|||||
Accounts
receivable – affiliates
|
2
|
10
|
|||||
Current
portion of intercompany note receivable – Genco
|
39
|
37
|
|||||
Current
portion of intercompany tax receivable – Genco
|
9
|
9
|
|||||
Advances
to money pool
|
-
|
1
|
|||||
Materials
and supplies
|
51
|
71
|
|||||
Other
current assets
|
43
|
46
|
|||||
Total
current assets
|
389
|
278
|
|||||
Property
and Plant, Net
|
1,160
|
1,155
|
|||||
Investments
and Other Assets:
|
|||||||
Intercompany
note receivable – Genco
|
87
|
126
|
|||||
Intercompany
tax receivable – Genco
|
111
|
115
|
|||||
Other
assets
|
29
|
27
|
|||||
Regulatory
assets
|
134
|
146
|
|||||
Total
investments and other assets
|
361
|
414
|
|||||
TOTAL
ASSETS
|
$ |
1,910
|
$ |
1,847
|
|||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Short-term
debt
|
$ |
135
|
$ |
35
|
|||
Accounts
and wages payable
|
44
|
36
|
|||||
Accounts
payable – affiliates
|
39
|
81
|
|||||
Taxes
accrued
|
6
|
10
|
|||||
Other
current liabilities
|
34
|
36
|
|||||
Total
current liabilities
|
258
|
198
|
|||||
Long-term
Debt, Net
|
471
|
471
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes and investment tax credits, net
|
275
|
297
|
|||||
Regulatory
liabilities
|
221
|
224
|
|||||
Accrued
pension and other postretirement benefits
|
83
|
90
|
|||||
Other
deferred credits and liabilities
|
44
|
24
|
|||||
Total
deferred credits and other liabilities
|
623
|
635
|
|||||
Commitments
and Contingencies (Notes 2 and 8)
|
|||||||
Stockholders'
Equity:
|
|||||||
Common
stock, no par value, 45.0 shares authorized – 25.5 shares
outstanding
|
-
|
-
|
|||||
Other
paid-in capital
|
190
|
190
|
|||||
Preferred
stock not subject to mandatory redemption
|
50
|
50
|
|||||
Retained
earnings
|
317
|
302
|
|||||
Accumulated
other comprehensive income
|
1
|
1
|
|||||
Total
stockholders' equity
|
558
|
543
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$ |
1,910
|
$ |
1,847
|
The
accompanying notes as they relate to CIPS are an integral part of these
consolidated financial statements.
15
CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY
|
|||||||
STATEMENT
OF CASH FLOWS
|
|||||||
(Unaudited)
(In millions)
|
|||||||
Six
Months Ended
|
|||||||
June
30,
|
|||||||
2007
|
2006
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$ |
16
|
$ |
14
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
33
|
31
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
1
|
-
|
|||||
Deferred
income taxes and investment tax credits, net
|
(10 | ) | (16 | ) | |||
Other
|
-
|
(1 | ) | ||||
Changes
in assets and liabilities:
|
|||||||
Receivables
|
13
|
39
|
|||||
Materials
and supplies
|
20
|
21
|
|||||
Accounts
and wages payable
|
(30 | ) | (8 | ) | |||
Taxes
accrued
|
(4 | ) | (19 | ) | |||
Assets,
other
|
6
|
22
|
|||||
Liabilities,
other
|
(4 | ) | (3 | ) | |||
Pension
and other postretirement obligations
|
3
|
-
|
|||||
Net
cash provided by operating activities
|
44
|
80
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(39 | ) | (41 | ) | |||
Proceeds
from intercompany note receivable – Genco
|
37
|
34
|
|||||
Changes
in money pool advances
|
1
|
(17 | ) | ||||
Net
cash used in investing activities
|
(1 | ) | (24 | ) | |||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
-
|
(25 | ) | ||||
Dividends
on preferred stock
|
(1 | ) | (1 | ) | |||
Capital
issuance costs
|
-
|
(1 | ) | ||||
Short-term
debt, net
|
100
|
-
|
|||||
Changes
in money pool borrowings
|
-
|
(2 | ) | ||||
Redemptions,
repurchases, and maturities:
|
|||||||
Long-term
debt
|
-
|
(20 | ) | ||||
Intercompany
note payable – UE
|
-
|
(67 | ) | ||||
Issuances
of long-term debt
|
-
|
61
|
|||||
Net
cash provided by (used in) financing activities
|
99
|
(55 | ) | ||||
Net
change in cash and cash equivalents
|
142
|
1
|
|||||
Cash
and cash equivalents at beginning of year
|
6
|
-
|
|||||
Cash
and cash equivalents at end of period
|
$ |
148
|
$ |
1
|
The
accompanying notes as they relate to CIPS are an integral part of these
consolidated financial statements.
16
AMEREN
ENERGY GENERATING COMPANY
|
|||||||||||||||
CONSOLIDATED
STATEMENT OF INCOME
|
|||||||||||||||
(Unaudited)
(In millions)
|
|||||||||||||||
Three
Months Ended
|
Six
Months Ended
|
||||||||||||||
June
30,
|
June
30,
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Operating
Revenues
|
$ |
185
|
$ |
238
|
$ |
428
|
$ |
485
|
|||||||
Operating
Expenses:
|
|||||||||||||||
Fuel
|
74
|
61
|
155
|
130
|
|||||||||||
Purchased
power
|
(1 | ) |
89
|
20
|
185
|
||||||||||
Other
operations and maintenance
|
49
|
47
|
83
|
79
|
|||||||||||
Depreciation
and amortization
|
18
|
17
|
36
|
35
|
|||||||||||
Taxes
other than income taxes
|
4
|
5
|
10
|
11
|
|||||||||||
Total
operating expenses
|
144
|
219
|
304
|
440
|
|||||||||||
Operating
Income
|
41
|
19
|
124
|
45
|
|||||||||||
Miscellaneous
Income
|
1
|
-
|
1
|
-
|
|||||||||||
Interest
Charges
|
14
|
15
|
28
|
30
|
|||||||||||
Income
Before Income Taxes
|
28
|
4
|
97
|
15
|
|||||||||||
Income
Taxes
|
11
|
2
|
37
|
7
|
|||||||||||
Net
Income
|
$ |
17
|
$ |
2
|
$ |
60
|
$ |
8
|
|||||||
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,
|
||||||
2007
|
2006
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$ |
1
|
$ |
1
|
|||
Accounts
receivable – affiliates
|
100
|
96
|
|||||
Accounts
receivable – trade
|
5
|
19
|
|||||
Materials
and supplies
|
97
|
96
|
|||||
Other
current assets
|
29
|
5
|
|||||
Total
current assets
|
232
|
217
|
|||||
Property
and Plant, Net
|
1,558
|
1,539
|
|||||
Intangible
Assets
|
64
|
74
|
|||||
Other
Assets
|
18
|
20
|
|||||
TOTAL
ASSETS
|
$ |
1,872
|
$ |
1,850
|
|||
LIABILITIES
AND STOCKHOLDER'S EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
portion of intercompany note payable – CIPS
|
$ |
39
|
$ |
37
|
|||
Borrowings
from money pool
|
239
|
123
|
|||||
Accounts
and wages payable
|
36
|
52
|
|||||
Accounts
payable – affiliates
|
73
|
66
|
|||||
Current
portion of intercompany tax payable – CIPS
|
9
|
9
|
|||||
Taxes
accrued
|
20
|
22
|
|||||
Other
current liabilities
|
21
|
22
|
|||||
Total
current liabilities
|
437
|
331
|
|||||
Long-term
Debt, Net
|
474
|
474
|
|||||
Intercompany
Note Payable – CIPS
|
87
|
126
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
146
|
165
|
|||||
Accumulated
deferred investment tax credits
|
8
|
9
|
|||||
Intercompany
tax payable – CIPS
|
111
|
115
|
|||||
Asset
retirement obligations
|
32
|
31
|
|||||
Accrued
pension and other postretirement benefits
|
40
|
34
|
|||||
Other
deferred credits and liabilities
|
31
|
2
|
|||||
Total
deferred credits and other liabilities
|
368
|
356
|
|||||
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
|
428
|
428
|
|||||
Retained
earnings
|
103
|
156
|
|||||
Accumulated
other comprehensive loss
|
(25 | ) | (21 | ) | |||
Total
stockholder's equity
|
506
|
563
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDER'S EQUITY
|
$ |
1,872
|
$ |
1,850
|
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,
|
|||||||
2007
|
2006
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$ |
60
|
$ |
8
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Gain
on sales of emission allowances
|
(1 | ) |
-
|
||||
Depreciation
and amortization
|
52
|
51
|
|||||
Deferred
income taxes and investment tax credits, net
|
8
|
(8 | ) | ||||
Other
|
1
|
(1 | ) | ||||
Changes
in assets and liabilities:
|
|||||||
Receivables
|
10
|
27
|
|||||
Materials
and supplies
|
(1 | ) | (26 | ) | |||
Accounts
and wages payable
|
13
|
36
|
|||||
Taxes
accrued, net
|
(2 | ) | (23 | ) | |||
Assets,
other
|
(26 | ) |
-
|
||||
Liabilities,
other
|
(2 | ) | (4 | ) | |||
Pension
and other postretirement obligations
|
3
|
3
|
|||||
Net
cash provided by operating activities
|
115
|
63
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(77 | ) | (39 | ) | |||
Purchases
of emission allowances
|
(5 | ) | (26 | ) | |||
Sales
of emission allowances
|
1
|
1
|
|||||
Net
cash used in investing activities
|
(81 | ) | (64 | ) | |||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
(113 | ) | (71 | ) | |||
Changes
in money pool borrowings
|
116
|
57
|
|||||
Intercompany
notes payable – CIPS
|
(37 | ) | (34 | ) | |||
Capital
contribution from parent
|
-
|
50
|
|||||
Net
cash provided by (used in) financing activities
|
(34 | ) |
2
|
||||
Net
change in cash and cash equivalents
|
-
|
1
|
|||||
Cash
and cash equivalents at beginning of year
|
1
|
-
|
|||||
Cash
and cash equivalents at end of period
|
$ |
1
|
$ |
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,
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Operating
Revenues:
|
|||||||||||||||
Electric
|
$ |
162
|
$ |
98
|
$ |
337
|
$ |
190
|
|||||||
Gas
|
60
|
48
|
195
|
198
|
|||||||||||
Other
|
1
|
-
|
1
|
-
|
|||||||||||
Total
operating revenues
|
223
|
146
|
533
|
388
|
|||||||||||
Operating
Expenses:
|
|||||||||||||||
Fuel
|
14
|
29
|
37
|
53
|
|||||||||||
Purchased
power
|
61
|
6
|
133
|
8
|
|||||||||||
Gas
purchased for resale
|
42
|
32
|
145
|
151
|
|||||||||||
Other
operations and maintenance
|
45
|
48
|
87
|
93
|
|||||||||||
Depreciation
and amortization
|
19
|
19
|
38
|
37
|
|||||||||||
Taxes
other than income taxes
|
6
|
4
|
14
|
13
|
|||||||||||
Total
operating expenses
|
187
|
138
|
454
|
355
|
|||||||||||
Operating
Income
|
36
|
8
|
79
|
33
|
|||||||||||
Other
Income and Expenses:
|
|||||||||||||||
Miscellaneous
income
|
-
|
1
|
2
|
1
|
|||||||||||
Miscellaneous
expense
|
(2 | ) | (1 | ) | (3 | ) | (2 | ) | |||||||
Total
other expenses
|
(2 | ) |
-
|
(1 | ) | (1 | ) | ||||||||
Interest
Charges
|
15
|
13
|
29
|
25
|
|||||||||||
Income
(Loss) Before Income Taxes and Preferred
|
|||||||||||||||
Dividends
of Subsidiaries
|
19
|
(5 | ) |
49
|
7
|
||||||||||
Income
Taxes (Benefit)
|
6
|
(6 | ) |
16
|
(3 | ) | |||||||||
Income
Before Preferred Dividends of Subsidiaries
|
13
|
1
|
33
|
10
|
|||||||||||
Preferred
Dividends of Subsidiaries
|
1
|
-
|
1
|
1
|
|||||||||||
Net
Income
|
$ |
12
|
$ |
1
|
$ |
32
|
$ |
9
|
|||||||
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,
|
||||||
2007
|
2006
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$ |
108
|
$ |
4
|
|||
Accounts
receivable – trade (less allowance for doubtful
|
|||||||
accounts
of $5 and $1, respectively)
|
49
|
47
|
|||||
Unbilled
revenue
|
35
|
45
|
|||||
Accounts
receivable – affiliates
|
30
|
10
|
|||||
Advances
to money pool
|
-
|
42
|
|||||
Materials
and supplies
|
79
|
93
|
|||||
Other
current assets
|
40
|
42
|
|||||
Total
current assets
|
341
|
283
|
|||||
Property
and Plant, Net
|
1,357
|
1,277
|
|||||
Investments
and Other Assets:
|
|||||||
Goodwill
|
542
|
542
|
|||||
Intangible
assets
|
45
|
48
|
|||||
Other
assets
|
19
|
16
|
|||||
Regulatory
assets
|
56
|
75
|
|||||
Total
investments and other assets
|
662
|
681
|
|||||
TOTAL
ASSETS
|
$ |
2,360
|
$ |
2,241
|
|||
LIABILITIES
AND STOCKHOLDER'S EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt
|
$ |
-
|
$ |
50
|
|||
Short-term
debt
|
465
|
215
|
|||||
Intercompany
note payable – Ameren
|
-
|
73
|
|||||
Accounts
and wages payable
|
40
|
54
|
|||||
Accounts
payable – affiliates
|
63
|
60
|
|||||
Taxes
accrued
|
3
|
3
|
|||||
Other
current liabilities
|
48
|
58
|
|||||
Total
current liabilities
|
619
|
513
|
|||||
Long-term
Debt, Net
|
539
|
542
|
|||||
Preferred
Stock of Subsidiary Subject to Mandatory
Redemption
|
18
|
18
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Accumulated
deferred income taxes, net
|
183
|
201
|
|||||
Accumulated
deferred investment tax credits
|
7
|
7
|
|||||
Regulatory
liabilities
|
67
|
73
|
|||||
Accrued
pension and other postretirement benefits
|
151
|
171
|
|||||
Other
deferred credits and liabilities
|
55
|
26
|
|||||
Total
deferred credits and other liabilities
|
463
|
478
|
|||||
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
|
627
|
627
|
|||||
Retained
earnings
|
43
|
11
|
|||||
Accumulated
other comprehensive income
|
32
|
33
|
|||||
Total
stockholder's equity
|
702
|
671
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDER'S EQUITY
|
$ |
2,360
|
$ |
2,241
|
|||
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,
|
|||||||
2007
|
2006
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$ |
32
|
$ |
9
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
38
|
50
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
1
|
-
|
|||||
Deferred
income taxes and investment tax credits
|
(3 | ) | (4 | ) | |||
Loss
on sale of noncore properties
|
-
|
4
|
|||||
Other
|
-
|
(1 | ) | ||||
Changes
in assets and liabilities:
|
|||||||
Receivables
|
(12 | ) |
55
|
||||
Materials
and supplies
|
14
|
20
|
|||||
Accounts
and wages payable
|
3
|
(20 | ) | ||||
Taxes
accrued
|
(3 | ) | (13 | ) | |||
Assets,
other
|
(2 | ) |
20
|
||||
Liabilities,
other
|
(7 | ) | (9 | ) | |||
Pension
and postretirement benefit obligations
|
1
|
1
|
|||||
Net
cash provided by operating activities
|
62
|
112
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(127 | ) | (48 | ) | |||
Proceeds
from note receivable – Resources Company
|
-
|
42
|
|||||
Proceeds
from sale of noncore properties
|
-
|
11
|
|||||
Changes
in money pool advances
|
42
|
-
|
|||||
Purchases
of emission allowances
|
-
|
(12 | ) | ||||
Sales
of emission allowances
|
-
|
1
|
|||||
Net
cash used in investing activities
|
(85 | ) | (6 | ) | |||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on common stock
|
-
|
(50 | ) | ||||
Capital
issuance costs
|
-
|
(1 | ) | ||||
Short-term
debt, net
|
250
|
-
|
|||||
Changes
in money pool borrowings
|
-
|
(89 | ) | ||||
Intercompany
note payable – Ameren, net
|
(73 | ) | (30 | ) | |||
Redemptions,
repurchases, and maturities of long-term debt
|
(50 | ) | (12 | ) | |||
Issuances
of long-term debt
|
-
|
96
|
|||||
Net
cash provided by (used in) financing activities
|
127
|
(86 | ) | ||||
Net
change in cash and cash equivalents
|
104
|
20
|
|||||
Cash
and cash equivalents at beginning of year
|
4
|
3
|
|||||
Cash
and cash equivalents at end of period
|
$ |
108
|
$ |
23
|
|||
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,
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Operating
Revenues:
|
|||||||||||||||
Electric
|
$ |
162
|
$ |
98
|
$ |
337
|
$ |
190
|
|||||||
Gas
|
60
|
48
|
195
|
198
|
|||||||||||
Other
|
1
|
-
|
1
|
-
|
|||||||||||
Total
operating revenues
|
223
|
146
|
533
|
388
|
|||||||||||
Operating
Expenses:
|
|||||||||||||||
Fuel
|
12
|
25
|
34
|
48
|
|||||||||||
Purchased
power
|
61
|
6
|
133
|
8
|
|||||||||||
Gas
purchased for resale
|
42
|
32
|
145
|
151
|
|||||||||||
Other
operations and maintenance
|
46
|
52
|
87
|
93
|
|||||||||||
Depreciation
and amortization
|
18
|
17
|
36
|
34
|
|||||||||||
Taxes
other than income taxes
|
5
|
4
|
13
|
13
|
|||||||||||
Total
operating expenses
|
184
|
136
|
448
|
347
|
|||||||||||
Operating
Income
|
39
|
10
|
85
|
41
|
|||||||||||
Other
Income and Expenses:
|
|||||||||||||||
Miscellaneous
income
|
1
|
-
|
2
|
-
|
|||||||||||
Miscellaneous
expense
|
(2 | ) | (1 | ) | (3 | ) | (2 | ) | |||||||
Total
other expenses
|
(1 | ) | (1 | ) | (1 | ) | (2 | ) | |||||||
Interest
Charges
|
5
|
4
|
11
|
8
|
|||||||||||
Income
Before Income Taxes
|
33
|
5
|
73
|
31
|
|||||||||||
Income
Taxes (Benefit)
|
12
|
(3 | ) |
26
|
6
|
||||||||||
Net
Income
|
21
|
8
|
47
|
25
|
|||||||||||
Preferred
Stock Dividends
|
1
|
1
|
1
|
1
|
|||||||||||
Net
Income Available to Common Stockholder
|
$ |
20
|
$ |
7
|
$ |
46
|
$ |
24
|
|||||||
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
|
|||||||
2007
|
2006
|
|||||||
ASSETS
|
||||||||
Current
Assets:
|
||||||||
Cash
and cash equivalents
|
$ |
95
|
$ |
3
|
||||
Accounts
receivable – trade (less allowance for doubtful
|
||||||||
accounts
of $5 and $1, respectively)
|
49
|
47
|
||||||
Unbilled
revenue
|
35
|
45
|
||||||
Accounts
receivable – affiliates
|
27
|
9
|
||||||
Advances
to money pool
|
-
|
42
|
||||||
Materials
and supplies
|
79
|
93
|
||||||
Other
current assets
|
32
|
32
|
||||||
Total
current assets
|
317
|
271
|
||||||
Property
and Plant, Net
|
1,356
|
1,275
|
||||||
Intangible
Assets
|
2
|
2
|
||||||
Other
Assets
|
22
|
18
|
||||||
Regulatory
Assets
|
56
|
75
|
||||||
TOTAL
ASSETS
|
$ |
1,753
|
$ |
1,641
|
||||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||||
Current
Liabilities:
|
||||||||
Current
maturities of long-term debt
|
$ |
-
|
$ |
50
|
||||
Short-term
debt
|
290
|
165
|
||||||
Accounts
and wages payable
|
40
|
54
|
||||||
Accounts
payable – affiliates
|
63
|
47
|
||||||
Taxes
accrued
|
3
|
3
|
||||||
Other
current liabilities
|
39
|
47
|
||||||
Total
current liabilities
|
435
|
366
|
||||||
Long-term
Debt, Net
|
148
|
148
|
||||||
Preferred
Stock Subject to Mandatory Redemption
|
18
|
18
|
||||||
Deferred
Credits and Other Liabilities:
|
||||||||
Accumulated
deferred income taxes, net
|
148
|
166
|
||||||
Accumulated
deferred investment tax credits
|
7
|
7
|
||||||
Regulatory
liabilities
|
198
|
206
|
||||||
Accrued
pension and other postretirement benefits
|
151
|
171
|
||||||
Other
deferred credits and liabilities
|
55
|
24
|
||||||
Total
deferred credits and other liabilities
|
559
|
574
|
||||||
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
|
429
|
415
|
||||||
Retained
earnings
|
145
|
99
|
||||||
Accumulated
other comprehensive income
|
-
|
2
|
||||||
Total
stockholders' equity
|
593
|
535
|
||||||
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$ |
1,753
|
$ |
1,641
|
||||
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,
|
||||||||
2007
|
2006
|
|||||||
Cash
Flows From Operating Activities:
|
||||||||
Net
income
|
$ |
47
|
$ |
25
|
||||
Adjustments
to reconcile net income to net cash
|
||||||||
provided
by operating activities:
|
||||||||
Depreciation
and amortization
|
37
|
40
|
||||||
Amortization
of debt issuance costs and premium/discounts
|
1
|
-
|
||||||
Deferred
income taxes and investment tax credits
|
(3 | ) | (3 | ) | ||||
Loss
on sale of noncore properties
|
-
|
6
|
||||||
Other
|
-
|
(1 | ) | |||||
Changes
in assets and liabilities:
|
||||||||
Receivables
|
(10 | ) |
53
|
|||||
Materials
and supplies
|
14
|
22
|
||||||
Accounts
and wages payable
|
16
|
(20 | ) | |||||
Taxes
accrued
|
(3 | ) | (17 | ) | ||||
Assets,
other
|
(7 | ) |
15
|
|||||
Liabilities,
other
|
(4 | ) | (5 | ) | ||||
Pension
and postretirement benefit obligations
|
1
|
4
|
||||||
Net
cash provided by operating activities
|
89
|
119
|
||||||
Cash
Flows From Investing Activities:
|
||||||||
Capital
expenditures
|
(127 | ) | (48 | ) | ||||
Proceeds
from sale of noncore properties
|
-
|
11
|
||||||
Changes
in money pool advances
|
42
|
-
|
||||||
Purchases
of emission allowances
|
-
|
(12 | ) | |||||
Sales
of emission allowances
|
-
|
1
|
||||||
Net
cash used in investing activities
|
(85 | ) | (48 | ) | ||||
Cash
Flows From Financing Activities:
|
||||||||
Dividends
on common stock
|
-
|
(50 | ) | |||||
Dividends
on preferred stock
|
(1 | ) | (1 | ) | ||||
Capital
issuance costs
|
-
|
(1 | ) | |||||
Short-term
debt, net
|
125
|
-
|
||||||
Changes
in money pool borrowings
|
-
|
(95 | ) | |||||
Redemptions,
repurchases, and maturities of long-term debt
|
(50 | ) |
-
|
|||||
Issuances
of long-term debt
|
-
|
96
|
||||||
Capital
contribution from parent
|
14
|
-
|
||||||
Net
cash provided by (used in) financing activities
|
88
|
(51 | ) | |||||
Net
change in cash and cash equivalents
|
92
|
20
|
||||||
Cash
and cash equivalents at beginning of year
|
3
|
2
|
||||||
Cash
and cash equivalents at end of period
|
$ |
95
|
$ |
22
|
||||
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
|
Six
Months Ended
|
||||||||||||||
June
30,
|
June
30,
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Operating
Revenues:
|
|||||||||||||||
Electric
|
$ |
280
|
$ |
271
|
$ |
552
|
$ |
513
|
|||||||
Gas
|
85
|
67
|
326
|
322
|
|||||||||||
Other
|
-
|
1
|
2
|
1
|
|||||||||||
Total
operating revenues
|
365
|
339
|
880
|
836
|
|||||||||||
Operating
Expenses:
|
|||||||||||||||
Purchased
power
|
178
|
171
|
367
|
348
|
|||||||||||
Gas
purchased for resale
|
56
|
36
|
241
|
237
|
|||||||||||
Other
operations and maintenance
|
63
|
61
|
122
|
120
|
|||||||||||
Depreciation
and amortization
|
19
|
18
|
40
|
37
|
|||||||||||
Amortization
of regulatory assets
|
4
|
-
|
8
|
-
|
|||||||||||
Taxes
other than income taxes
|
16
|
16
|
37
|
38
|
|||||||||||
Total
operating expenses
|
336
|
302
|
815
|
780
|
|||||||||||
Operating
Income
|
29
|
37
|
65
|
56
|
|||||||||||
Other
Income and Expenses:
|
|||||||||||||||
Miscellaneous
income
|
3
|
1
|
5
|
2
|
|||||||||||
Miscellaneous
expense
|
-
|
(1 | ) | (1 | ) | (2 | ) | ||||||||
Total
other income
|
3
|
-
|
4
|
-
|
|||||||||||
Interest
Charges
|
20
|
12
|
36
|
24
|
|||||||||||
Income
Before Income Taxes
|
12
|
25
|
33
|
32
|
|||||||||||
Income
Taxes
|
5
|
9
|
13
|
12
|
|||||||||||
Net
Income
|
7
|
16
|
20
|
20
|
|||||||||||
Preferred
Stock Dividends
|
-
|
-
|
1
|
1
|
|||||||||||
Net
Income Available to Common Stockholder
|
$ |
7
|
$ |
16
|
$ |
19
|
$ |
19
|
|||||||
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,
|
||||||
2007
|
2006
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$ |
143
|
$ |
-
|
|||
Accounts
receivable - trade (less allowance for doubtful
|
|||||||
accounts
of $11 and $3, respectively)
|
124
|
105
|
|||||
Unbilled
revenue
|
78
|
101
|
|||||
Accounts
receivable – affiliates
|
-
|
1
|
|||||
Materials
and supplies
|
93
|
122
|
|||||
Other
current assets
|
38
|
27
|
|||||
Total
current assets
|
476
|
356
|
|||||
Property
and Plant, Net
|
2,169
|
2,134
|
|||||
Investments
and Other Assets:
|
|||||||
Investment
in IP SPT
|
9
|
8
|
|||||
Goodwill
|
214
|
214
|
|||||
Other
assets
|
51
|
62
|
|||||
Regulatory
assets
|
368
|
401
|
|||||
Total
investments and other assets
|
642
|
685
|
|||||
TOTAL
ASSETS
|
$ |
3,287
|
$ |
3,175
|
|||
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of long-term debt to IP SPT
|
$ |
51
|
$ |
51
|
|||
Short-term
debt
|
325
|
75
|
|||||
Borrowings
from money pool
|
-
|
43
|
|||||
Accounts
and wages payable
|
76
|
119
|
|||||
Accounts
payable – affiliates
|
51
|
67
|
|||||
Taxes
accrued
|
5
|
7
|
|||||
Other
current liabilities
|
65
|
72
|
|||||
Total
current liabilities
|
573
|
434
|
|||||
Long-term
Debt, Net
|
768
|
772
|
|||||
Long-term
Debt to IP SPT
|
47
|
92
|
|||||
Deferred
Credits and Other Liabilities:
|
|||||||
Regulatory
liabilities
|
90
|
110
|
|||||
Accrued
pension and other postretirement benefits
|
214
|
230
|
|||||
Accumulated
deferred income taxes
|
132
|
138
|
|||||
Other
deferred credits and other noncurrent liabilities
|
98
|
53
|
|||||
Total
deferred credits and other liabilities
|
534
|
531
|
|||||
Commitments
and Contingencies (Notes 2 and 8)
|
|||||||
Stockholders’
Equity:
|
|||||||
Common
stock, no par value, 100.0 shares authorized – 23.0 shares
outstanding
|
-
|
-
|
|||||
Other
paid-in-capital
|
1,194
|
1,194
|
|||||
Preferred
stock not subject to mandatory redemption
|
46
|
46
|
|||||
Retained
earnings
|
120
|
101
|
|||||
Accumulated
other comprehensive income
|
5
|
5
|
|||||
Total
stockholders’ equity
|
1,365
|
1,346
|
|||||
TOTAL
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$ |
3,287
|
$ |
3,175
|
|||
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,
|
|||||||
2007
|
2006
|
||||||
Cash
Flows From Operating Activities:
|
|||||||
Net
income
|
$ |
20
|
$ |
20
|
|||
Adjustments
to reconcile net income to net cash
|
|||||||
provided
by operating activities:
|
|||||||
Depreciation
and amortization
|
42
|
15
|
|||||
Amortization
of debt issuance costs and premium/discounts
|
4
|
2
|
|||||
Deferred
income taxes
|
6
|
20
|
|||||
Changes
in assets and liabilities:
|
|||||||
Receivables
|
5
|
66
|
|||||
Materials
and supplies
|
29
|
31
|
|||||
Accounts
and wages payable
|
(40 | ) | (62 | ) | |||
Assets,
other
|
(7 | ) |
12
|
||||
Liabilities,
other
|
2
|
(24 | ) | ||||
Pension
and other postretirement benefit obligations
|
12
|
5
|
|||||
Net
cash provided by operating activities
|
73
|
85
|
|||||
Cash
Flows From Investing Activities:
|
|||||||
Capital
expenditures
|
(92 | ) | (82 | ) | |||
Other
|
(1 | ) |
-
|
||||
Net
cash used in investing activities
|
(93 | ) | (82 | ) | |||
Cash
Flows From Financing Activities:
|
|||||||
Dividends
on preferred stock
|
(1 | ) | (1 | ) | |||
Capital
issuance costs
|
-
|
(1 | ) | ||||
Short-term
debt, net
|
250
|
-
|
|||||
Changes
in money pool borrowings, net
|
(43 | ) | (21 | ) | |||
Redemptions,
repurchases and maturities of long-term debt
|
(43 | ) | (46 | ) | |||
Issuance
of long-term debt
|
-
|
75
|
|||||
Overfunding
of TFNs
|
-
|
(8 | ) | ||||
Net
cash provided by (used in) financing activities
|
163
|
(2 | ) | ||||
Net
change in cash and cash equivalents
|
143
|
1
|
|||||
Cash
and cash equivalents at beginning of year
|
-
|
-
|
|||||
Cash
and cash equivalents at end of period
|
$ |
143
|
$ |
1
|
|||
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, 2007
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’s primary assets are 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.
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 and natural gas transmission and distribution business
and a
non-rate-regulated electric generation business (through its subsidiary
AERG), all in Illinois.
|
·
|
IP,
or Illinois Power Company, also known as AmerenIP, operates a
rate-regulated electric and natural gas transmission and distribution
business in Illinois.
|
Ameren
has various other subsidiaries responsible for the short- and long-term
marketing of power, procurement of fuel, management of commodity risks, and
provision of other shared services. Ameren has an 80% ownership interest
in EEI
through UE and Development Company, which each own 40% of EEI. Ameren
consolidates EEI for financial reporting purposes, while UE reports EEI under
the equity method. The following table presents summarized financial information
of EEI for the three months and six months ended June 30, 2007 and
2006.
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Operating
revenues
|
$ |
109
|
$ |
88
|
$ |
206
|
$ |
184
|
|||||||
Operating
income
|
51
|
42
|
105
|
98
|
|||||||||||
Net
income
|
32
|
26
|
66
|
60
|
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. 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 the prior year’s financial statements to conform to 2007 reporting. These
financial statements should be read in conjunction with the financial statements
and the notes thereto included in the Form 10-K.
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, 2007 and
2006,
due to an immaterial number of stock options, restricted stock and performance
share units outstanding.
29
Long-term
Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation
Plan
A
summary of nonvested shares as of
June 30, 2007, and changes during the six-month period ended June 30, 2007,
under the Long-term Incentive Plan of 1998, as amended, and the 2006 Omnibus
Incentive Compensation Plan (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,
2007
|
338,516
|
$ |
56.07
|
377,776
|
$ |
45.79
|
||||||||
Granted(a)
|
357,573
|
59.60
|
-
|
-
|
||||||||||
Dividends
|
-
|
-
|
7,849
|
49.56
|
||||||||||
Forfeitures
|
(9,667 | ) |
56.31
|
(5,841 | ) |
46.47
|
||||||||
Vested(b)
|
(11,566 | ) |
59.30
|
(70,391 | ) |
43.84
|
||||||||
Nonvested
at June 30,
2007
|
674,856
|
$ |
57.88
|
309,393
|
$ |
46.23
|
(a)
|
Includes
performance share units (share units) granted to certain executive
and
non-executive officers and other eligible employees in February
2007 under
the 2006 Plan.
|
(b)
|
Share
units vested due to 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.
|
The
fair
value of each share unit awarded in February 2007 under the 2006 Plan was
determined to be $59.60 based on Ameren’s closing common share price of $53.99
per share at the grant date and lattice simulations used to estimate expected
share payout based on Ameren’s attainment of certain financial measures relative
to the designated peer group. The significant assumptions used to calculate
fair
value also included a three-year risk-free rate of 4.735%, dividend yields
of
2.3% to 5.2% for the peer group, volatility of 12.91% to 18.33% for the peer
group, and Ameren’s maintenance of its $2.54 annual dividend over the
performance period.
Ameren
recorded compensation expense
of $4 million and $3 million for the quarters ended June 30, 2007 and 2006,
respectively, and a related tax benefit of $2 million and $1 million for
the quarters ended June 30, 2007 and 2006, respectively. Ameren recorded
compensation expense of $9 million and $5 million for each of the six-month
periods ended June 30, 2007 and 2006, respectively, and a related tax benefit
of
$4 million and $2 million for the six-month periods ended June 30, 2007 and
2006, respectively. As of June 30, 2007, total compensation cost of $29 million
related to nonvested awards not yet recognized is expected to be recognized
over
a weighted-average period of 3 years.
Accounting
Changes and Other Matters
FASB
Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an
Interpretation of SFAS No. 109 (FIN 48)
FIN
48 addresses the determination of
whether tax benefits claimed or expected to be claimed on a tax return should
be
recorded in the financial statements. Under FIN 48, Ameren may recognize
the tax
benefit from an uncertain tax position only if it is more likely than not
that
the tax position will be sustained on examination by the taxing authorities,
based on the technical merits of the position. The tax benefits recognized
in
the financial statements from such a position are measured based on the largest
benefit that has a greater than 50% likelihood of being realized upon ultimate
settlement. FIN 48 also provides guidance on derecognition of income tax
assets
and liabilities, classification of current and deferred income tax assets
and
liabilities, accounting for interest and penalties on income taxes, accounting
for income taxes in interim periods, and requires expanded
disclosures.
The
Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The
amount
of unrecognized tax benefits as of January 1, 2007, was $155 million, $58
million,
$15
million, $36 million, $18 million, $18 million and $12 million for Ameren,
UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. Of these unrecognized
tax
benefits on January 1, 2007, $20 million, $6 million, less than $1 million,
less
than $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, and
CILCORP, respectively, would impact the respective company’s effective tax rate,
if recognized.
As
of
January 1, 2007, the Ameren Companies adopted a policy of recognizing interest
and penalties accrued on tax liabilities on a gross basis as interest expense
or
penalty expense in the statements of income. Prior to January 1, 2007, the
Ameren Companies recognized such items in the provision for taxes on a
net-of-tax basis. As of January 1, 2007, Ameren, UE, CIPS, Genco, CILCORP,
CILCO, and IP had recorded a liability of $12 million, $5 million, less
than $1 million, $4 million, $1 million, less than $1 million, and less
than $1
million, respectively, for the payment of interest with respect to unrecognized
tax benefits and no amount for penalties with respect to unrecognized tax
benefits.
All
of
the Ameren Companies’ federal income tax returns are closed through 2001. The
Ameren Companies are currently under federal income tax return examination
for
years 2002 through 2004. State income tax returns are generally subject to
examination for a period of three years
30
after
filing of the respective return. The state impact of any federal changes
remains
subject to examination by various states for a period of up to one year after
formal notification to the states. The Ameren Companies do not have state
income
tax returns in the process of examination. The Ameren Companies also do not
have
material state income tax issues in the process of administrative appeals
or
litigation.
The
Ameren Companies are not aware of
an event that is reasonably possible of occurring that would cause the total
amount of unrecognized tax benefits to significantly increase or decrease
within
twelve months after the date of the Ameren Companies’ adoption of FIN
48.
SFAS
No. 157, Fair Value Measurements
In
September 2006, the FASB issued SFAS
No. 157, which defines fair value, establishes a framework for measuring
fair
value, and expands disclosures about fair value measurements. SFAS No. 157
clarifies that fair value is a market-based measurement that should be
determined based on the assumptions that market participants would use in
pricing an asset or liability. This standard is effective as of the beginning
of
our 2008 fiscal year. We are still determining the impact the adoption of
SFAS
No. 157 will have on our results of operations, financial position, and
liquidity, if any; however, at this time, we do not expect the impact to
be
material.
SFAS
No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities, Including an Amendment of SFAS No. 115
In
February 2007, the FASB issued SFAS No. 159, which permits companies
to choose to measure many financial instruments and certain assets and
liabilities at fair value that are not currently required to be measured
at fair
value on an instrument-by-instrument basis. Entities electing the fair value
option will be required to recognize changes in fair value in earnings and
to
expense upfront cost and fees associated with the item for which the fair
value
option is elected. SFAS No. 159 is effective as of the beginning of our 2008
fiscal year. We are currently evaluating whether we will elect the fair value
option for any of our eligible financial instruments and other
items.
FSP
FIN 39-1, Amendment of FASB Interpretation No. 39
In
April 2007, the FASB issued FSP
FIN 39-1, effective for us as of the beginning of our 2008 fiscal year. FSP
FIN 39-1 permits companies to offset fair value amounts recognized
for the right to reclaim cash collateral (a receivable) or the obligation
to
return cash collateral (a liability) against fair value amounts recognized
for
derivative instruments that are executed with the same counterparty under
the
same master netting arrangement. We are currently evaluating whether we will
elect to apply the accounting policies permitted under this pronouncement.
The
adoption of FSP FIN 39-1 will have no impact on net income.
Goodwill
and Intangible Assets
Goodwill.
Goodwill represents the excess of the purchase price of an acquisition
over
the fair value of the net assets acquired. We evaluate goodwill for impairment
in the fourth quarter of each year, or more frequently if events and
circumstances indicate that the asset might be impaired. Ameren’s and IP’s
goodwill relates to the acquisitions of IP and an additional 20% ownership
interest in EEI in 2004, and Ameren’s and CILCORP’s goodwill relates to the
acquisitions of CILCORP and Medina Valley in 2003. For the period from January
1, 2007 to June 30, 2007, there were no changes in the carrying amount of
goodwill.
Intangible
Assets. At June 30, 2007, intangible assets
consisted of emission allowances of $206 million at Ameren, $58 million at
UE, $64 million at Genco, $2 million at CILCORP and $45 million at CILCO.
Emission allowances consist of various individual emission allowance
certificates and do not have expiration dates. Emission allowances are charged
to fuel expense as they are used in operations. During the second quarter
of
2006, a $4 million impairment was recorded for customer contracts.
The
following table presents the net amount of emission allowances consumed or
(sold) for Ameren, UE, Genco, CILCORP and CILCO during the three months and
six
months ended June 30, 2007 and 2006.
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Ameren(a)
|
$ |
13
|
$ |
14
|
$ |
20
|
$ |
25
|
|||||||
UE
|
-
|
-
|
(3
|
) | (2 | ) | |||||||||
Genco
|
8
|
7
|
15
|
15
|
|||||||||||
CILCORP(b)
|
1
|
6
|
3
|
11
|
|||||||||||
CILCO
|
(1 | ) |
3
|
-
|
6
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries and
intercompany eliminations.
|
(b)
|
Includes
allowances consumed that were recorded through purchase
accounting.
|
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 the statement of income. Excise taxes reflected
on
Illinois electric customer bills are imposed on the consumer and are therefore
not included in revenues and expenses. They are recorded as tax collections
payable and included in Taxes Accrued. 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, 2007
and
2006:
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Ameren
|
$ |
40
|
$ |
39
|
$ |
82
|
$ |
85
|
|||||||
UE
|
28
|
27
|
50
|
52
|
|||||||||||
CIPS
|
3
|
3
|
8
|
9
|
|||||||||||
CILCORP
|
3
|
2
|
7
|
6
|
|||||||||||
CILCO
|
3
|
2
|
7
|
6
|
|||||||||||
IP
|
6
|
7
|
17
|
18
|
Asset
Retirement Obligations
AROs
at
Ameren and UE increased compared to December 31, 2006, to reflect the accretion
of obligations to their fair values.
NOTE
2 – RATE AND REGULATORY MATTERS
Below
is
a summary of significant regulatory proceedings and related lawsuits. We
are
unable to predict the ultimate outcome of these matters, the timing of the
final decisions of the various agencies and courts, 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 a proposed average increase in electric rates of 17.7%, or $361
million based on a requested return on equity of 12.0%. This rate increase
filing was based on a test year ended June 30, 2006, and was updated for
known
and measurable items through January 1, 2007. In May 2007, the MoPSC issued
an
order, as clarified, granting UE a $43 million increase in base rates for
electric service based on a return on equity of 10.2% and a capital structure
of
52% common equity. New electric rates became effective June 4, 2007. The
MoPSC
order also included the following significant provisions:
·
|
Acceptance
without rate adjustment of the expiration of UE’s cost-based power supply
contract with EEI, which expired in December
2005.
|
·
|
Allowance
of the full cost of certain CTs purchased or built in the past
few years
to be included in UE’s rate base.
|
·
|
Establishment
of a regulatory tracking mechanism, through the use of a regulatory
liability account, for gains on sales of SO2
emission
allowances , net of SO2
premiums
incurred under the terms of coal procurement contracts, plus any
SO2
discounts received under such contracts. These deferred amounts
will
be addressed as part of the fuel expense calculation in UE’s next rate
case. The MoPSC allowed an annual base level of SO2
emission
allowance sales of up to $5 million, which UE can recognize in
its
statement of income.
|
·
|
Approval
of a regulatory tracking mechanism for pension and postretirement
benefit
costs.
|
·
|
Change
of income tax method associated with cost of property removal,
net of
salvage, to the normalization method of accounting, which reduced
income
tax expense in the calculation of UE’s electric rates and for financial
reporting purposes.
|
·
|
Establishment
of off-system sales base level of $230 million used in determining
UE’s revenue requirement.
|
·
|
Extension
of UE’s Callaway nuclear plant and fossil generation plant lives used
in
calculating depreciation expense for electric rates and financial
reporting purposes.
|
·
|
MoPSC
staff directed to review a possible loss in capacity sales as a
result of
the breach of the upper reservoir of the Taum Sauk pumped-storage
hydroelectric facility.
|
·
|
Establishment
of a requirement to fund low-income energy assistance and energy
conservation programs; half of such funding will be recoverable
through
rates to customers.
|
·
|
Denial
of UE’s request to implement a fuel and purchased power cost recovery
mechanism.
|
In
June
2007, the MoPSC denied UE’s and other intervenors’ applications for rehearing
with respect to certain aspects of the MoPSC rate order. In July 2007, UE
appealed certain aspects of the MoPSC decision, principally the 10.2% return on
equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson
City, Missouri. The Office of Public Counsel and the Missouri attorney general,
who were both intervenors in the electric rate case, also appealed certain
aspects of the MoPSC decision to the Circuit Court of Cole County.
Gas
In
March
2007, a stipulation and agreement was approved by the MoPSC, which resolved
a
July 2006 request by UE to the MoPSC to increase annual natural gas delivery
revenues by $11 million. The stipulation and agreement authorized an increase
in
annual natural gas delivery
32
revenues
of $6 million, effective April 1, 2007. Other principal provisions of the
stipulation and agreement include:
·
|
UE
agreed not to file a natural gas delivery rate case before March
15, 2010.
This agreement does not prevent UE from filing to recover infrastructure
costs through a statutory infrastructure system replacement surcharge
(ISRS) during this three-year rate moratorium. The return on equity
to be
used by UE for purposes of any future ISRS tariff filing is
10.0%.
|
·
|
Authorization
for UE to transition from four PGA rates to a single PGA rate for
all its
gas customers.
|
Taum
Sauk
In
June 2007, the MoPSC opened an
investigation of the breach of the upper reservoir at UE’s Taum Sauk
pumped-storage hydroelectric facility in December 2005. There is no statutory
deadline for the completion of this investigation. See Note 8 – Commitments and
Contingencies for additional information.
Illinois
Electric
Under
the
Illinois Customer Choice Law, as amended, CIPS’, CILCO’s and IP’s rates were
frozen through January 1, 2007.New electric rates for CIPS, CILCO and IP
went
into effect on January 2, 2007, reflecting delivery service tariffs approved
by
the ICC in November 2006 and full cost recovery of power purchased on behalf
of
Ameren Illinois Utilities’ customers in accordance with a January 2006 order
that approved the power procurement auction and related tariffs. As a result
of
these new electric rates going into effect, the estimated average annual
residential rate overall increase in 2007 was expected to be 40% to 55% over
2006 rates. The estimated average annual residential rate overall increase
for
electric heat customers was expected to be 60% to 80% over 2006
rates.
Due
to the magnitude of these rate
increases, various legislators supported legislation that would have reduced
and
frozen the electric rates of CIPS, CILCO and IP to the rates that were in
effect
prior to January 2, 2007, and would have imposed a tax on electric generation
in
Illinois to help fund customer assistance programs. The Illinois
governor also supported rate rollback and freeze legislation. In July 2007,
an agreement was reached among key stakeholders in Illinois that could avoid
such legislation and addresses the increase in electric rates and the future
power procurement process in Illinois. The terms of the agreement, which
includes a comprehensive rate relief and customer assistance program, are
set
forth in a letter dated July 24, 2007, to the leaders of the Illinois General
Assembly and the Illinois attorney general, in a release and settlement
agreement with the Illinois attorney general, in funding agreements among
the
parties contributing to the rate relief and assistance programs and in
legislation (Proposed Legislation), which was passed by the Illinois General
Assembly in late July 2007. The settlement agreement will be effective only
upon
enactment of this Proposed Legislation by the Illinois governor. The following
is a discussion of this agreement, including its impact on future power
procurement for the Ameren Illinois Utilities, and outstanding significant
regulatory and related legal matters affecting our Illinois electric
operations.
Electric
Agreement
The
agreement was the result of many
months of negotiations among leaders of the House of Representatives and
Senate
in Illinois, the office of the Illinois attorney general, Ameren, on behalf
of
its affiliates, including Marketing Company, Genco, and AERG, the Ameren
Illinois Utilities, Exelon Corporation (Exelon), on behalf of Exelon Generation
Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility
subsidiary, Dynegy Holdings Inc., Midwest Generation, LLC, and MidAmerican
Energy Company. The comprehensive program would provide approximately $1
billion
of funding for rate relief for certain electric customers in Illinois, including
approximately $488 million to customers of the Ameren Illinois Utilities.
Pursuant to the rate relief program, the Ameren Illinois Utilities, Genco
and
AERG, have agreed to make aggregate contributions of $150 million over a
four-year period, with $60 million coming from the Ameren Illinois
Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62
million from Genco and $28 million from AERG. Below is a summary of the total
customer relief and assistance to be provided to the customers of the Ameren
Illinois Utilities, the Ameren Illinois Utilities’, Genco’s and AERG’s portion
of the funding that is expected to be disbursed and the expected charges
to
earnings as a result of the program and agreement, subject to enactment of
the
Proposed Legislation:
Total
Relief/Assistance to Ameren
Illinois
Customers
|
Ameren
Subsidiaries’ Funding(a)
|
Estimated
Ameren
Earnings Per Share
Impact(b)
|
|||||||||
2007
|
$ |
253,000,000
|
$ |
86,000,000
|
$ |
0.26
|
|||||
2008
|
132,000,000
|
37,000,000
|
0.11
|
||||||||
2009
|
97,000,000
|
25,000,000
|
0.07
|
||||||||
2010
|
6,000,000
|
2,000,000
|
0.01
|
||||||||
Total
|
$ |
488,000,000
|
$ |
150,000,000
|
$ |
0.45
|
(a)
|
Includes
a $4.5 million contribution in 2007 towards funding of a newly-created
IPA.
|
(b)
|
Includes
estimated cost of proposed forgiveness of outstanding customer
late
payment fees.
|
The
Ameren Illinois Utilities, Genco and AERG will recognize in their financial
statements the costs of their respective rate relief contributions in a manner
corresponding with the timing of the funding included in the above table
if the
Proposed Legislation is enacted into law by the Illinois governor.
33
Other
electric generators and
utilities in Illinois have agreed to contribute $851 million to the
comprehensive rate relief and customer assistance program. Contributions
by the
other electric generators (the Generators) and utilities to the comprehensive
program are subject to funding agreements. Under these agreements, at the
end of
each month, the Ameren Illinois Utilities would bill the Generators for their
proportionate share of that month’s rate relief and assistance, which would be
due in 30 days. If any escrow funds have been provided by the Generators,
these
funds would be drawn prior to seeking reimbursement from the
Generators.
The
rate relief program would
preserve existing rates and rate structures, and the Ameren Illinois Utilities
would continue to have the right to file new electric delivery service rate
cases with the ICC at the respective utility’s discretion. The redesign of
all-electric customers’ rates is still subject to an ongoing case with the ICC
designed to reduce seasonal fluctuations for residential customers who use
large
amounts of electricity while allowing utilities to fully recover costs. We
expect the ICC will issue a final order by September 2007, which would allow
implementation of any rate design changes by the next winter heating season.
The
agreement provides that if legislation is enacted in Illinois before August
1,
2011, freezing or reducing retail electric rates, or imposing or authorizing
a
new tax, special assessment or fee on the generation of electricity, then
the
remaining commitments under this agreement would expire and any funds set
aside
in support of the commitments would be refunded to the utilities and
Generators.
As
part of the agreement, the current
reverse auction used for power procurement in Illinois would be discontinued
immediately and replaced with a new power procurement process. In 2008, Illinois
utilities would contract for their necessary baseload, intermediate and peaking
power requirements through a request-for-proposal process, subject to ICC
review
and approval. Also as part of the agreement, existing supply contracts from
the
September 2006 reverse auction would remain in place. As part of the rate
relief
program, the Ameren Illinois Utilities entered into financial contracts with
Marketing Company (for the benefit of Genco and AERG), to lock-in prices
for 400
to 1,000 megawatts annually of their baseload power requirements from 2008
through 2012 at relevant market prices. These contracts do not include capacity
and are not load-following products. These contracts have been executed but
are
not effective, and prices are subject to change, until enactment of the Proposed
Legislation by the Illinois governor.
Period
|
Volume
|
June
1, 2008 – December 31, 2008
|
400
MW
|
January
1, 2009 – May 31, 2009
|
400
MW
|
June
1, 2009 – December 31, 2009
|
800
MW
|
January
1, 2010 – May 31, 2010
|
800
MW
|
June
1, 2010 – December 31, 2010
|
1,000
MW
|
January
1, 2011 – December 31, 2011
|
1,000
MW
|
January
1, 2012 – December 31, 2012
|
1,000
MW
|
Under
the
terms of the agreement, these financial contracts would be deemed prudent,
and
the Ameren Illinois Utilities would be permitted full cost recovery of their
costs in rates.
Beginning
in June 2009 and thereafter, power procurement would be accomplished through
competitive requests for proposals to supply the separate baseload, intermediate
and peaking power needs of the utility instead of the full requirements,
load-following supply contracts previously procured through a reverse auction.
The power procurement process that is expected to be implemented would require
the IPA to develop an annual Procurement Plan (Plan) for the Ameren Illinois
Utilities and Commonwealth Edison. Each Plan would govern a utility’s
procurement of power to meet the expected load requirements that are not
met by
pre-existing contracts or generation facilities. Subject to ICC approval,
the
Ameren Illinois Utilities would be allowed to lease, or invest in, generation
facilities. The objective of each Plan would be to ensure adequate, reliable,
affordable, efficient, and environmentally sustainable electric service at
the
lowest total cost over time taking into account any benefits of price stability
for the utilities’ eligible retail customers. The power procurement process
provides that each Plan be submitted to the ICC for initial approval; if
approved, the final design and implementation of a Plan would be overseen
by an
independent procurement administrator selected by the proposed IPA and a
procurement monitor selected by the ICC. The IPA would have broad authority
to
assist in the procurement of electric power for residential and nonresidential
customers beginning in June 2009. Winning proposals would be selected on
the
basis of price, compared for reasonableness to benchmarks developed by the
procurement administrator and procurement monitor, and approved by the
ICC.
The
power procurement process would
provide that each electric utility in Illinois file proposed tariffs with
the
ICC, which would be designed to pass-through to customers the costs of procuring
electric power supply with no mark-up on the price paid by the utility, plus
any
reasonable costs that the utility incurred in arranging and providing for
the
supply of electric power. All such procurement costs would be deemed to have
been prudently incurred and recoverable through rates.
The
agreement provides that the
Ameren Illinois Utilities would have a right to maintain membership in a
FERC-approved regional transmission organization of their choice for a period
of
at least 15 years.
The
agreement also includes a
commitment to energy conservation programs designed to reduce energy consumption
through increased energy efficiency and demand response. In addition, 2%
of the
Illinois utilities’ electricity would be procured from renewable sources
beginning June 1, 2008, with that percentage increasing in subsequent years,
subject to limits on customer rate impacts. The provision for
34
full
and
timely recovery of the cost of these commitments is also included in the
agreement.
The
agreement provides that all
pending litigation and regulatory actions by the office of the Illinois attorney
general relating to the reverse auction procurement process, which was used
to
determine market-based rates effective January 1, 2007, and the electric
space
heating marketing practices of the Ameren Illinois Utilities would be withdrawn
with prejudice. The litigation and regulatory actions include those filed
by the
office of the attorney general with the FERC, the ICC, the United States
Court
of Appeals for the District of Columbia Circuit and the Circuit Court of
the
First Judicial Circuit Jackson County, Illinois and the Appellate Court of
Illinois, Second Judicial Circuit.
Finally,
the agreement would
establish the authority to obtain accelerated review by the ICC of a merger
or
combination of the three Ameren Illinois Utilities, if requested in the
future.
Delivery
Service Rate
Cases
CIPS,
CILCO and IP filed rate cases
with the ICC in December 2005 to modify their electric delivery service rates
effective January 2, 2007. CIPS, CILCO and IP requested to increase their
annual
revenues for electric delivery service by $202 million in the aggregate (CIPS
-
$14 million, CILCO - $43 million and IP - $145 million). In November
2006, the ICC issued an order approving an annual revenue increase for electric
delivery service of $97 million in the aggregate (CIPS - $8 million decrease,
CILCO - $21 million increase and IP - $84 million increase). In December
2006,
the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the
November 2006 order on the recovery of certain administrative and general
expenses, totaling $50 million, that were disallowed. In May 2007, the ICC
issued an order denying recovery of these expenses. No further appeal of
the ICC
order is being pursued by the Ameren Illinois Utilities. Prior to January
2,
2007, most customers of the Ameren Illinois Utilities were taking service
under
a frozen bundled electric rate, which included the cost of power, so these
delivery service revenue changes do not directly correspond to a change in
CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery
service rates.
Appeals
of 2006 ICC Procurement
Order
Various
parties, including CIPS,
CILCO, IP, the Illinois attorney general, CUB, and ELPC, appealed to Illinois
district appellate courts the ICC’s denial of rehearing requests with respect to
its January 2006 order, which approved the power procurement auction and
related
tariffs. In August 2006, the Supreme Court of Illinois ordered that the appeals
be consolidated in the appellate court for the Second Judicial Circuit in
Illinois. The Second Judicial Circuit appellate court granted a motion of
the
Illinois attorney general to dismiss CIPS’, CILCO’s and IP’s appeal regarding
the need for an annual postauction prudence review claiming that it was filed
prematurely. CIPS, CILCO and IP appealed that decision to the Illinois Supreme
Court, where it was denied in March 2007. The Illinois attorney general’s appeal
at the Second Judicial Circuit appellate court would be withdrawn as part
of the
agreement discussed above. CUB’s and ELPC’s appeals at the Second Judicial
Circuit appellate court are still pending.
Power
Procurement Auction Class
Action Lawsuits
Ameren,
CIPS, CILCO, IP, Commonwealth
Edison Company and its parent company, Exelon, and 15 electricity suppliers,
including Marketing Company, which are selling power to the Illinois utilities
pursuant to contracts entered into as a result of the September 2006 power
procurement auction, were named as defendants in two similar class action
lawsuits filed in the Circuit Court of Cook County, Illinois in March 2007.
The
asserted class seeks to represent all customers who purchased electric service
from Commonwealth Edison Company or the Ameren Illinois Utilities. Both lawsuits
allege, among other things, that the Illinois utilities and the power suppliers
illegally manipulated prices in the September 2006 power procurement auction.
The relief sought in both lawsuits is actual damages to be determined at
trial
and legal costs, including attorneys’ fees. One of the lawsuits also seeks
punitive damages and recovery of illegal profits and excludes the Ameren
Illinois Utilities from the requests for relief. In April 2007, the defendants
in these lawsuits filed notices removing these cases to the U.S. District
Court
for the Northern District of Illinois. Defendants have pending motions to
dismiss. These two class action lawsuits are not affected by the agreement
discussed above.
Summary
The
settlement agreement will not be effective until enabling legislation, which
has
been passed by the Illinois General Assembly, is enacted into law by the
Illinois governor. We are unable to predict the actions the Illinois
General Assembly, the Illinois attorney general or Illinois governor may
take
that might affect electric rates, the power procurement process for CIPS,
CILCO
and IP or pending litigation and regulatory actions if the settlement agreement
is not enacted into law. If any decision is made or action occurs 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, and
such
decision or action is not promptly enjoined, it could result in material
adverse
consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences
could include a significant drop in credit ratings to deep junk (or speculative)
status, the inability to access the capital markets on reasonable terms,
higher
borrowing costs, higher power supply costs, an inability to make timely
energy
35
infrastructure
investments, requirements to post collateral or other assurances for certain
obligations, significant risk of disruption in electric and gas service,
significant job losses, and ultimately the finanical insolvency and bankruptcy
of CIPS, CILCORP, CILCO and IP. In addition, Ameren, CILCORP and IP would
need to assess whether they are required to record a charge for goodwill
impairment for the goodwill that was recorded when Ameren acquired CILCORP
and
IP. Furthermore, if the Ameren Illinois Utilities are unable to recover
their costs from customers, the utilities could be required to cease applying
for the electric portions of their businesses SFAS No. 71. "Accounting for
the
Effects of Certain Types of Regulation," which allows the Ameren Illinois
Utilities to defer certain costs pursuant to actions of rate regulators and
to
recover such costs in rates charged to customers. This could result in the
elimination of the Ameren Illinois Utilities' regulatory assets and liabilities
recorded on their, CILCORP's and Ameren's balance sheets and a one-time
extraordinary charge on their, CILCORP's and Ameren's statements of income
that
could be material, Ameren's, CILCORP's and IP's assessment of any goodwill
impairment and Ameren's, CIPS, CILCORP's, CILCO's and IP's continued application
of SFAS No.71, for the electric portions of the Ameren Illinois Utilities'
businesses, would include consideration of, among other things, their views
on
the ultimate success of their legal actions and strategies to enjoin the
implementation of, and ultimately invalidate, any enacted legislation, decision,
or other action that would impair the Ameren Illinois Utilities' ability to
recover their costs form customers through rates.
Federal
FERC
Order – MISO
Charges
In
May 2007 Ameren Services, on
behalf of UE, CIPS CILCO and IP, filed with the United States Court of
Appeals
for the District of Columbia Circuit, an appeal of the FERC’s March 2007 order
involving the reallocation of certain MISO operational costs among MISO
participants, retroactive to 2005. We are unable to predict how the court
might
rule; however, the range of potential outcomes spans from requiring additional
payments of up to $9 million from IP if the Court rules against us, to
receiving
refunds of up to $28 million (UE - $20 million, CIPS - $5 million, CILCO
- $4 million, Genco - $5 million, and Marketing Company - $3 million,
net of additional payments of up to $9 million from IP) if it rules in
our
favor.
UE
Power
Purchase Agreement with Entergy Arkansas, Inc.
In
July 2007, as a consequence of a
series of orders issued by FERC addressing a complaint filed by the Louisiana
Public Service Commission against Entergy Arkansas, Inc. (Entergy) and
certain
of its affiliates, which alleged unjust and unreasonable cost allocations,
Entergy commenced billing UE for additional charges under a 165 megawatt
power
purchase agreement. These additional charges to UE are expected to approximate
$13 million for the remainder of 2007 and additional amounts during the
term of
the power purchase agreement, which terminates effective August 25, 2009.
Although UE was not a party to the FERC proceedings that gave rise to these
increases in charges, UE is seeking intervention in a related FERC proceeding
for the purpose of challenging the increases. UE is unable to predict whether
FERC will grant its request to intervene or the nature of any substantive
relief
that UE may obtain from FERC.
NOTE
3 – CREDIT FACILITIES AND LIQUIDITY
The
liquidity needs of the Ameren Companies are typically supported through
the use
of available cash, commercial paper issuances and drawings under committed
bank
credit facilities.
The
following table summarizes the borrowing activity and relevant interest
rates as
of June 30, 2007, under the $1.15 billion credit facility and 2007 and 2006
$500 million credit facilities:
$1.15
Billion Credit Facility(a)
|
Ameren
(Parent)
|
UE
|
Genco
|
Ameren
Total
|
|||||||||||
June
30, 2007:
|
|||||||||||||||
Average
daily borrowings outstanding during 2007
|
$ |
180
|
$ |
496
|
$ |
-
|
$ |
676
|
|||||||
Outstanding
short-term debt at period end
|
350
|
426
|
-
|
776
|
|||||||||||
Weighted-average
interest rate during 2007
|
5.82 | % | 5.72 | % |
-
|
5.75 | % | ||||||||
Peak
short-term borrowings during 2007
|
$ |
350
|
$ |
506
|
-
|
$ |
856
|
||||||||
Peak
interest rate during 2007
|
8.25 | % | 5.92 | % |
-
|
8.25 | % |
(a)
|
Includes
commercial paper programs at Ameren and UE supported by this
credit
facility.
|
36
2007
$500 Million Credit Facility
|
CIPS
|
CILCORP
(Parent)
|
CILCO
(Parent)
|
IP
|
AERG
|
Total
|
|||||||||||||||||
June
30, 2007:
|
|||||||||||||||||||||||
Average
daily borrowings outstanding during 2007
|
$ |
-
|
$ |
125
|
$ |
-
|
$ |
149
|
$ |
90
|
$ |
364
|
|||||||||||
Outstanding
short-term debt at period end
|
-
|
125
|
-
|
200
|
100
|
425
|
|||||||||||||||||
Weighted-average
interest rate during 2007
|
-
|
6.91 | % |
-
|
6.54 | % | 6.85 | % | 6.74 | % | |||||||||||||
Peak
short-term borrowings during 2007
|
$ |
-
|
$ |
125
|
$ |
-
|
$ |
200
|
$ |
100
|
$ |
425
|
|||||||||||
Peak
interest rate during 2007
|
-
|
7.04 | % |
-
|
6.64 | % | 7.02 | % | 7.04 | % | |||||||||||||
2006
$500 Million Credit Facility
|
CIPS
|
CILCORP
(Parent)
|
CILCO
(Parent)
|
IP
|
AERG
|
Total
|
|||||||||||||||||
June
30, 2007:
|
|||||||||||||||||||||||
Average
daily borrowings outstanding during 2007
|
$ |
78
|
$ |
44
|
$ |
45
|
$ |
50
|
$ |
78
|
$ |
295
|
|||||||||||
Outstanding
short-term debt at period end
|
135
|
50
|
75
|
125
|
115
|
500
|
|||||||||||||||||
Weighted-average
interest rate during 2007
|
6.48 | % | 6.79 | % | 6.11 | % | 6.55 | % | 6.85 | % | 6.58 | % | |||||||||||
Peak
short-term borrowings during 2007
|
$ |
135
|
$ |
50
|
$ |
75
|
$ |
125
|
$ |
115
|
$ |
500
|
|||||||||||
Peak
interest rate during 2007
|
6.64 | % | 7.04 | % | 6.47 | % | 6.64 | % | 8.25 | % | 8.25 | % |
At
June 30, 2007, Ameren and certain
of its subsidiaries had $2.15 billion of committed credit facilities, consisting
of the three facilities shown above, in the amounts of $1.15 billion, $500
million and $500 million maturing in July 2010, January 2010 and January
2010,
respectively.
Effective
July 12, 2007, the termination date for UE’s and Genco’s direct borrowing
sublimit under the $1.15 billion credit facility was extended to July 10,
2008,
pursuant to the annual 364-day renewal provisions of the facility. The
$1.15
billion credit facility will terminate on July 14, 2010 with respect to
Ameren.
The
2007
$500 million credit facility was entered into on February 9, 2007, by CIPS,
CILCORP, CILCO, IP and AERG. Borrowing authority under this facility was
effective immediately for CILCORP and AERG, and effective for CIPS, CILCO
and IP
on March 9, 2007, upon the receipt of regulatory approvals.
The
obligations of IP under the 2007
$500 million credit facility were secured by the issuance on March 9, 2007,
of
mortgage bonds in the amount of $200 million. CIPS and CILCO cannot utilize
any
amount of their borrowing authority under the 2007 $500 million credit
facility
until they reduce their borrowing authority by an equal amount under the
2006
$500
million credit facility. If CIPS or CILCO elect to transfer borrowing authority
from the 2006 $500 million credit facility to the 2007 $500 million credit
facility, that company must retire an appropriate amount of first mortgage
bonds
issued with respect to the 2006 $500 million credit facility and issue
new bonds
in an equal amount to secure its obligations under the 2007 $500 million
credit
facility. In July 2007, CILCO permanently reduced its $150 million of borrowing
authority under the 2006 $500 million credit facility by $75 million and
shifted
that amount of capacity to the 2007 $500 million credit facility. CILCO
is now
considered a borrower under both credit facilities and is subject to the
covenants of both.
The
$1.15 billion credit facility was
used to support the commercial paper programs that included $126 million
of
outstanding commercial paper of UE as of June 30, 2007.
Access
to the $1.15 billion credit
facility, the 2007 $500 million credit facility and the 2006 $500 million
credit
facility for the Ameren Companies and AERG is subject to reduction as borrowings
are made by affiliates. Ameren and UE are currently limited in their access
to
the commercial paper market as a result of downgrades in their short-term
credit
ratings.
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. Ameren Services is responsible
for
operation and administration of the money pool agreements.
Utility
CIPS,
CILCO and IP borrow from each other through the utility money pool agreement
subject to applicable regulatory short-term borrowing authorizations. AERG
may
make loans to, but may not borrow from, the utility money pool. Although
UE and
Ameren Services are parties to the utility money pool agreement, they are
not
currently borrowing or lending under the agreement. The average interest
rate
for borrowing under the utility money pool for the three months and six
months
ended June 30, 2007, was 5.6% and 5.8%, respectively (2006 –
5.0% and 4.7%, respectively).
Non-state-regulated
Subsidiaries
Ameren
Services, Resources Company,
Genco, AERG, Marketing Company, AFS, Ameren Energy and other non-state-regulated
Ameren subsidiaries have the ability, subject to Ameren parent company
authorization, to access funding from Ameren’s $1.15 billion credit facility
through a non-state-regulated subsidiary money pool agreement subject to
applicable regulatory short-term borrowing authorizations. At June 30,
2007,
$369 million was available through the non-state-regulated subsidiary money
pool, excluding additional funds available through excess cash balances.
The
average
37
interest
rate for borrowing under the non-state-regulated subsidiary money pool
for the
three months and six months ended June 30, 2007, was 5.1% and 4.9%,
respectively (2006 – 4.6% and 4.5%, respectively).
See
Note 7 – Related Party Transactions
for the amount of interest income (expense) from the money pool arrangements
recorded by the Ameren Companies for the three months and six months ended
June
30, 2007 and 2006.
Indebtedness
Provisions and Other Covenants
The
information below presents a
summary of the Ameren Companies’ compliance with indebtedness provisions and
other covenants. See Note 5 – Credit Facilities and Liquidity in the Form 10-K,
for a detailed description of those provisions.
The
Ameren Companies’ bank credit facilities contain provisions which, among other
things, place restrictions on the ability to incur liens, sell assets,
and merge
with other entities. The $1.15 billion credit facility contains provisions
that
limit total indebtedness of each of Ameren, UE and Genco to 65% of total
consolidated capitalization pursuant to a calculation defined in the facility.
Exceeding these debt levels would result in a default under the $1.15 billion
credit facility.
The
$1.15
billion credit facility also contains default provisions, 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 facility
are
several and not joint, and except under limited circumstances, the obligations
of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS,
CILCORP, CILCO, AERG and IP are not considered subsidiaries for purposes
of the
cross-default or other provisions.
Under
the
$1.15 billion credit facility, restrictions apply limiting investments
in and
other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries
by
Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP,
AERG
and their subsidiaries are excluded for purposes of determining compliance
with
the 65% total consolidated indebtedness to total consolidated capitalization
financial covenant in the facility.
Both
the
2007 $500 million credit facility and the 2006 $500 million credit facility
entered into by CIPS, CILCORP, CILCO, IP and AERG, discussed above, limit
the
indebtedness of each borrower to 65% of consolidated total capitalization
pursuant to a calculation set forth in the facilities. Events of default
under
these facilities apply separately to each borrower (and, except in the
case of
CILCORP, to their subsidiaries), and an event of default under these facilities
does not constitute an event of default under the $1.15 billion credit
facility
and vice versa. In addition, if CIPS’, CILCO’s or IP’s senior secured long-term
debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term
debt securities, have received a below-investment-grade credit rating by
either
Moody’s or S&P, then such borrower will be limited to capital stock dividend
payments of $10 million per year each, while such below-investment-grade
credit
rating is in effect. On July 26, 2006, Moody’s downgraded CILCORP’s senior
unsecured long-term debt credit rating to below investment-grade, causing
it to
be subject to this dividend payment limitation. A similar restriction applies
to
AERG if its debt-to-operating cash flow ratio, as set forth in these facilities,
is above a 3.0 to 1.0 ratio. As of June 30, 2007, AERG did not meet this
test in
the 2007 $500 million credit facility and the 2006 $500 million credit
facility
and thus was subject to the dividend restriction. CIPS, CILCO and IP are
not
currently limited in their dividend payments by this provision of the 2007
$500
million or 2006 $500 million credit facilities. Ameren’s access to dividends
from CILCO and AERG is limited by dividend restrictions at CILCORP.
The
2007 $500 million credit facility
and the 2006 $500 million credit facility also limit the amount of other
secured indebtedness issuable by each borrower thereunder. 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 $425
million
(including the principal amount of CILCORP’s outstanding senior notes and senior
bonds) under the 2007 $500 million credit facility and $550 million (including
the principal amount of CILCORP’s outstanding senior notes and senior bonds as
well as amounts drawn under the 2007 $500 million credit facility) under
the
2006 $500 million credit facility, secured in each case by the pledge of
CILCO
common stock. For AERG, other secured debt is limited to $100 million under
the
2007 $500 million credit facility and $200 million under the 2006 $500
million
credit facility secured on an equal basis with its obligations under the
facilities. The limitations on other secured debt at CILCORP and AERG in
the
2007 $500 million credit facility are subject to adjustment based on the
borrowing sublimits of these entities under this facility or under the
2006 $500
million credit facility. In addition, the 2007 $500 million credit facility
and the 2006 $500 million credit facility prohibit CILCO from issuing any
preferred stock if, after giving effect to such issuance, the aggregate
liquidation value of all CILCO preferred stock issued after February 9,
2007 and
July 14, 2006, respectively, would exceed $50 million.
The
2007 $500 million credit 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 (subject to, in the case
of
CIPS and CILCO,
38
their
then current borrowing sublimits under the facility and similar provisions
in
the 2006 facility): 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, but prior to December 31, 2009 - $150 million, on and
after
December 31, 2009 - $200 million; CILCO, prior to December 31, 2007 - $25
million, on and after December 31, 2007, but prior to December 31, 2008
- $50 million, on and after December 31, 2008, but prior to December 31,
2009 - $75 million, on and after December 31, 2009 - $150 million; and
IP, prior
to December 31, 2008 - $100 million, on and after December 31, 2008, but
prior
to December 31, 2009 - $200 million, on and after December 31, 2009 - $350
million.
The
2006 $500 million credit facility
provides that CIPS, CILCO and IP will agree to reserve future bonding capacity
under their respective mortgage indentures 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.
As
of
June 30, 2007, the ratio of total indebtedness to total consolidated
capitalization, calculated in accordance with the provisions of the $1.15
billion credit facility for Ameren, UE and Genco was 53%, 53% and 54%,
respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated
in
accordance with the provisions of the 2007 $500 million credit facility
and 2006
$500 million credit facility, were 53%, 57%, 43%, 47% and 40%,
respectively.
None
of Ameren’s credit facilities or
financing arrangements contain credit rating triggers that would cause
an event
of default or acceleration of repayment of outstanding balances. At June
30,
2007, the Ameren Companies were in compliance with their credit facility
provisions and covenants.
NOTE
4 – LONG-TERM DEBT AND EQUITY FINANCINGS
Ameren
Under
DRPlus, pursuant to an effective
SEC Form S-3 registration statement, and under our 401(k) plans, pursuant to
effective SEC Form S-8 registration statements, Ameren issued a total of
0.5
million new shares of common stock valued at $27 million and 0.9 million
new
shares valued at $48 million in the three months and six months ended
June 30, 2007, respectively.
In
February 2007, $100 million of
Ameren’s 2002 5.70% notes matured and were retired.
In
May 2007, $250 million of Ameren’s
senior notes related to its 2002 equity security units matured and were
retired.
UE
In
June
2007, UE issued, pursuant to an effective SEC Form S-3 shelf registration
statement, $425 million of 6.40% senior secured notes due June 15, 2017,
with
interest payable semi-annually on June 15 and December 15 of each year,
beginning in December 2007. UE received net proceeds of $422 million, which
were
used to repay short-term debt.
In
connection with UE’s June 2007 issuance of $425 million of senior secured
notes, UE agreed, for so long as those senior secured notes are outstanding,
that it would not, prior to June 15, 2012, optionally redeem, purchase
or
otherwise retire in full its outstanding first mortgage bonds not subject
to
release provisions thus causing a first mortgage bond release date to occur.
Such release date is the date at which the security provided by the pledge
under
UE’s first mortgage indenture would no longer be available to holders of any
outstanding series of its senior secured notes and such indebtedness would
become senior unsecured indebtedness ranking equally with any other outstanding
senior unsecured indebtedness of UE. UE further agreed that if such release
date
occurred between June 15, 2012 and the maturity date of the senior secured
notes
issued in June 2007 of June 15, 2017, the interest rate for these senior
secured
notes will be subject to an increase of up to a maximum of 2.00% if within
30
days (subject to extension if and for so long as the rating for such senior
secured notes is under consideration for possible downgrade) of such release
date Moody’s or S&P downgrades the rating assigned to these senior secured
notes below investment grade as a result of the occurrence of the release.
Any
interest rate increase on these senior secured notes will take effect from
the
first day of the interest period during which such rating downgrade requires
an
increase in the interest rate.
CIPS
See
Note 5 – Credit Facilities and
Liquidity in the Form 10-K regarding CIPS’ agreement under the 2007 $500 million
credit facility and the 2006 $500 million credit facility to reserve future
bonding capacity under its mortgage indenture.
CILCORP
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 (2006 -
$1 million) and $3 million (2006 - $3 million) for the three months and
six
months ended June 30, 2007, respectively, and was included as a reduction
to
interest expense in the Consolidated Statements of Income of Ameren
39
and
CILCORP. See Note 5 – Credit Facilities and Liquidity in the Form 10-K,
regarding CILCORP’s pledge of the common stock of CILCO as security for
CILCORP’s obligations under the 2007 $500 million credit facility and the 2006
$500 million credit facility.
CILCO
In
January 2007, $50 million of
CILCO’s 7.50% first mortgage bonds matured and were retired.
See
Note 5 – Credit Facilities and
Liquidity in the Form 10-K regarding CILCO’s agreement under the 2007 $500
million credit facility and the 2006 $500 million credit facility to reserve
future bonding capacity under its mortgage indenture.
In
July 2007, 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 2007.
IP
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 (2006 - $3 million)
and
$6 million (2006 - $7 million) for the three months and six months ended
June
30, 2007, respectively, and was included as a reduction to interest expense
in
the Consolidated Statements of Income of Ameren and IP.
See
Note 5 – Credit Facilities and
Liquidity in the Form 10-K regarding IP’s agreement under the 2007 $500 million
credit facility and the 2006 $500 million credit facility to reserve future
bonding capacity under its mortgage indenture.
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 Form 10-K,
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 and bonds and preferred stock
issuable based on the 12 months ended June 30, 2007, at an assumed interest
and
dividend rate of 7%.
Required
Interest
Coverage
Ratio(a)(b)
|
Actual
Interest
Coverage
Ratio
|
Bonds
Issuable(c)(d)
|
Required
Dividend
Coverage
Ratio(e)
|
Actual
Dividend
Coverage
Ratio
|
Preferred
Stock
Issuable
|
||||||||||
UE
|
≥2.0
|
3.9
|
$ |
1.982
|
≥2.5
|
43.9
|
$ |
1,405
|
|||||||
CIPS
|
≥2.0
|
3.8
|
178
|
≥1.5
|
2.1
|
211
|
|||||||||
CILCO
|
≥2.0(f)
|
11.3
|
84
|
≥2.5
|
36.5
|
370(g)
|
|||||||||
IP
|
≥2.0
|
3.3
|
258
|
≥1.5
|
1.8
|
205
|
(a) | Coverage required on the annual interest charges on mortgage bonds outstanding and to be issued. |
(b) | Coverage is not required in certain cases when additional mortgage bonds are issued on the basis of retired bonds. |
(c)
|
Amount
of bonds issuable based on either meeting required coverage
ratios or
unfunded property additions, whichever is more restrictive.
In addition to
these tests, UE, CIPS, CILCO and IP have the ability to issue
bonds based
upon retired bond capacity of $17 million, $3 million, $175
million,
and $914 million, respectively, for which no earnings coverage
test
is required.
|
(d)
|
Amounts
are net of future bonding capacity restrictions agreed to by
CIPS, CILCO
and IP under the 2007 $500 million credit facility and the
2006 $500
million credit facility entered into by these companies. See
Note 3 –
Credit Facilities and Liquidity for further
discussion.
|
(e)
|
Coverage
required on the annual interest charges on all long-term debt
(CIPS-only)
and the annual dividend on preferred stock outstanding and
to be issued,
as required in the respective company’s articles of incorporation. For
CILCO, this ratio must be met for a period of 12 consecutive
calendar
months within the 15 months immediately preceding the
issuance.
|
(f)
|
In
lieu of meeting the interest coverage ratio requirement, CILCO
may attempt
to meet an earnings requirement of at least 12% of the principal
amount of
all mortgage bonds outstanding and to be issued. For the three
months and
six months ended June 30, 2007, CILCO had earnings equivalent
to at least
43% of the principal amount of all mortgage bonds
outstanding.
|
(g)
|
See
Note 3 – Credit Facilities and Liquidity for a discussion regarding
a
restriction on the issuance of preferred stock by CILCO under
the
2007 500 million credit facility and the 2006 $500 million credit
facility.
|
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, 2007.
40
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,
to make certain principal or interest payments, to make certain loans to
affiliates, or to incur additional indebtedness. The following table summarizes
these ratios for the 12 months ended June 30, 2007:
Required
Interest
Coverage
Ratio
|
Actual
Interest
Coverage
Ratio
|
Required
Debt–to-
Capital
Ratio
|
Actual
Debt–to-
Capital
Ratio
|
|
Genco
(a)
|
≥1.75(b)
|
5.9
|
≤60%
|
52%
|
CILCORP(c)
|
≥2.2
|
3.3
|
≤67%
|
29%
|
(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
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.
|
Genco’s
ratio restrictions under its indenture may be disregarded if both Moody’s and
S&P reaffirm the ratings of Genco in place at the time of the debt
incurrence after considering the additional indebtedness. In the event
CILCORP
is not in compliance with these restrictions, CILCORP may make payments
of
dividends or intercompany loans if its senior long-term debt rating is
at least
BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At June 30, 2007,
CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were B+,
Ba2, and BB+, respectively. The common stock of CILCO is pledged as security
to
the holders of CILCORP’s senior notes and bonds and credit facility
obligations.
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, 2007, none of the Ameren
Companies had any off-balance-sheet financing arrangements, other than
operating
leases entered into in the ordinary course of business. None of the Ameren
Companies expect to engage in any significant off-balance-sheet financing
arrangements in the near future.
NOTE
5 – OTHER INCOME AND EXPENSES
The
following table presents Other Income and Expenses for each of the Ameren
Companies for the three months and six months ended June 30, 2007 and
2006:
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Ameren:(a)
|
|||||||||||||||
Miscellaneous
income:
|
|||||||||||||||
Interest
and dividend
income
|
$ |
14
|
$ |
8
|
$ |
25
|
$ |
11
|
|||||||
Allowance
for equity funds used
during construction
|
-
|
-
|
-
|
1
|
|||||||||||
Other
|
6
|
3
|
9
|
4
|
|||||||||||
Total
miscellaneous
income
|
$ |
20
|
$ |
11
|
$ |
34
|
$ |
16
|
|||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ | (4 | ) | $ | (1 | ) | $ | (4 | ) | $ | (1 | ) | |||
Total
miscellaneous
expense
|
$ | (4 | ) | $ | (1 | ) | $ | (4 | ) | $ | (1 | ) | |||
UE:
|
|||||||||||||||
Miscellaneous
income:
|
|||||||||||||||
Interest
and dividend
income
|
$ |
8
|
$ |
8
|
$ |
15
|
$ |
10
|
|||||||
Allowance
for equity funds used
during construction
|
-
|
-
|
-
|
1
|
|||||||||||
Other
|
4
|
-
|
5
|
1
|
|||||||||||
Total
miscellaneous
income
|
$ |
12
|
$ |
8
|
$ |
20
|
$ |
12
|
|||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ | (6 | ) | $ | (2 | ) | $ | (8 | ) | $ | (4 | ) | |||
Total
miscellaneous
expense
|
$ | (6 | ) | $ | (2 | ) | $ | (8 | ) | $ | (4 | ) | |||
CIPS:
|
|||||||||||||||
Miscellaneous
income:
|
|||||||||||||||
Interest
and dividend
income
|
$ |
4
|
$ |
4
|
$ |
8
|
$ |
8
|
|||||||
Other
|
1
|
-
|
-
|
1
|
|||||||||||
Total
miscellaneous
income
|
$ |
5
|
$ |
4
|
$ |
8
|
$ |
9
|
|||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ | (1 | ) | $ |
-
|
$ | (1 | ) | $ | (1 | ) | ||||
Total
miscellaneous
expense
|
$ | (1 | ) | $ |
-
|
$ | (1 | ) | $ | (1 | ) |
41
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Genco:
|
|||||||||||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ |
1
|
$ |
-
|
$ |
1
|
$ |
-
|
|||||||
Total
miscellaneous
expense
|
$ |
1
|
$ |
-
|
$ |
1
|
$ |
-
|
|||||||
CILCORP:
|
|||||||||||||||
Miscellaneous
income:
|
|||||||||||||||
Interest
and dividend
income
|
$ |
-
|
$ |
1
|
$ |
2
|
$ |
1
|
|||||||
Total
miscellaneous
income
|
$ |
-
|
$ |
1
|
$ |
2
|
$ |
1
|
|||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ | (2 | ) | $ | (1 | ) | $ | (3 | ) | $ | (2 | ) | |||
Total
miscellaneous
expense
|
$ | (2 | ) | $ | (1 | ) | $ | (3 | ) | $ | (2 | ) | |||
CILCO:
|
|||||||||||||||
Miscellaneous
income:
|
|||||||||||||||
Interest and
dividend
income
|
$ |
1
|
$ |
-
|
$ |
2
|
$ |
-
|
|||||||
Total
miscellaneous
income
|
$ |
1
|
$ |
-
|
$ |
2
|
$ |
-
|
|||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ | (2 | ) | $ | (1 | ) | $ | (3 | ) | $ | (2 | ) | |||
Total
miscellaneous
expense
|
$ | (2 | ) | $ | (1 | ) | $ | (3 | ) | $ | (2 | ) | |||
IP:
|
|||||||||||||||
Miscellaneous
income:
|
|||||||||||||||
Interest
and dividend
income
|
$ |
2
|
$ |
1
|
$ |
3
|
$ |
1
|
|||||||
Other
|
1
|
-
|
2
|
1
|
|||||||||||
Total
miscellaneous
income
|
$ |
3
|
$ |
1
|
$ |
5
|
$ |
2
|
|||||||
Miscellaneous
expense:
|
|||||||||||||||
Other
|
$ |
-
|
$ | (1 | ) | $ | (1 | ) | $ | (2 | ) | ||||
Total
miscellaneous
expense
|
$ |
-
|
$ | (1 | ) | $ | (1 | ) | $ | (2 | ) |
(a)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries
and
intercompany eliminations.
|
NOTE
6 – DERIVATIVE FINANCIAL INSTRUMENTS
The
following table presents the
pretax net gain or loss for the three and six months ended June 30, 2007
and
2006 of power hedges included in Operating Revenues – Electric. This pretax net
gain or loss represents the impact of discontinued cash flow hedges, the
ineffective portion of cash flow hedges,and
the
reversal of amounts previously recorded in OCI due to transactions
being delivered or settled:
Three
Months
|
Six
Months
|
||||||||||||||
Gains
( Losses)
|
2007
|
2006
|
2007
|
2006
|
|||||||||||
Ameren
|
$ |
8
|
$ |
1
|
$ |
13
|
$ | (1 | ) | ||||||
UE
|
(4 | ) |
-
|
(2 | ) |
2
|
|||||||||
Genco
|
-
|
-
|
-
|
1
|
|||||||||||
IP
|
-
|
(1 | ) |
-
|
(5 | ) |
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, 2007:
Ameren(a)
|
UE
|
CIPS
|
Genco
|
CILCORP/
CILCO
|
IP
|
||||||||||||||||||
Derivative
instruments carrying value:
|
|||||||||||||||||||||||
Other
assets
|
$ |
83
|
$ |
9
|
$ |
1
|
$ |
-
|
$ |
5
|
$ |
-
|
|||||||||||
Other
deferred credits and
liabilities
|
14
|
4
|
-
|
2
|
1
|
-
|
|||||||||||||||||
Gains
(losses) deferred in Accumulated OCI:
|
|||||||||||||||||||||||
Power
forwards(b)
|
55
|
7
|
-
|
-
|
-
|
-
|
|||||||||||||||||
Interest
rate swaps(c)
|
3
|
-
|
-
|
3
|
-
|
-
|
|||||||||||||||||
Gas
swaps and futures
contracts(d)
|
3
|
-
|
1
|
-
|
4
|
-
|
|||||||||||||||||
SO2
futures
contracts
|
(1 | ) |
-
|
-
|
(1 | ) |
-
|
-
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries
and
intercompany eliminations.
|
(b)
|
Represents
the mark-to-market value for the hedged portion of electricity
price
exposure for periods of up to four years, including $38 million
over the
next year.
|
(c)
|
Represents
a gain associated with interest rate swaps at Genco that were
a partial
hedge of the interest rate on debt issued in June 2002. The swaps
cover
the first 10 years of debt that has a 30-year maturity and the
gain in OCI
is amortized over a 10-year period that began in June
2002.
|
(d)
|
Represents
gains associated with natural gas swaps and futures contracts.
The swaps
are a partial hedge of our natural gas requirements through March
2011.
|
42
Other
Derivatives
The
following table presents the net change in market value for the three months
and
six months ended June 30, 2007 and 2006, of option and swap transactions
used to
manage our positions in SO2 allowances, coal, and heating oil, and
nonhedge power and gas trading activity. Certain of these transactions
are
treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended. The net change in the market
value of SO2, coal and heating oil options and swaps is recorded as
Operating Expenses – Fuel and Purchased Power. The nonhedge power and gas swaps
are recorded in Operating Revenues – Electric and Operating Revenues –
Gas.
Three
Months
|
Six
Months
|
||||||||||||||
Gains
(Losses)
|
2007
|
2006
|
2007
|
2006
|
|||||||||||
SO2
options and
swaps:
|
|||||||||||||||
Ameren
|
$ |
2
|
$ | (2 | ) | $ |
6
|
$ | (3 | ) | |||||
UE
|
1
|
(1 | ) |
5
|
(2 | ) | |||||||||
Genco
|
1
|
(1 | ) |
1
|
(5 | ) | |||||||||
Coal
options:
|
|||||||||||||||
Ameren
|
1
|
(1 | ) |
2
|
(1 | ) | |||||||||
UE
|
1
|
(1 | ) |
2
|
(1 | ) | |||||||||
Heating
oil options:
|
|||||||||||||||
Ameren
|
-
|
-
|
3
|
-
|
|||||||||||
Nonhedge
power swaps and forwards:
|
|||||||||||||||
Ameren
|
(5 | ) |
-
|
(4 | ) |
-
|
|||||||||
UE
|
(4 | ) |
-
|
(4 | ) |
-
|
|||||||||
Nonhedge
gas futures:
|
|||||||||||||||
Ameren
|
2
|
-
|
2
|
-
|
|||||||||||
UE
|
2
|
-
|
2
|
-
|
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
13 – Related Party Transactions under Part II, Item 8 of the Form 10-K. Below
are updates to several of these related party agreements. Also see Note
2 – Rate
and Regulatory Matters and Note 8 – Commitments and Contingencies for
information on an electric settlement agreement reached in July 2007 among
key
stakeholders in Illinois and reflected in the Proposed Legislation that
addresses electric rate increases and the future power procurement process
in
Illinois. As part of the electric agreement in Illinois, the Ameren
Illinois Utilities, Genco and AERG agreed to make contributions
of $150 million as part of a comprehensive program providing
approximately $1 billion of funding for rate relief to certain Illinois
electric
customers, including customers of the Ameren Illinois Utilities. Also as
part of
the electric agreement, the Ameren Illinois Utilities entered into financial
contracts with Marketing Company to lock-in prices for a portion of their
baseload power requirements from 2008 to 2012 at relevant market prices.
The
agreement and the financial contracts are not effective until the Proposed
Legislation is enacted into law by the Illinois governor.
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, 2007 and
2006:
Three
Months
|
Six
Months
|
|||
2007
|
2006
|
2007
|
2006
|
|
Genco
sales to
Marketing
Company(a)
|
-
|
5,296
|
-
|
10,887
|
Marketing
Company
sales
to CIPS(a)
|
-
|
2,997
|
-
|
6,076
|
Genco
sales to
Marketing
Company(b)
|
3,838
|
-
|
7,957
|
-
|
AERG
sales to
Marketing
Company(b)
|
1,154
|
-
|
2,642
|
-
|
Marketing
Company
sales
to CIPS(c)
|
562
|
-
|
1,181
|
-
|
Marketing
Company
sales
to CILCO(c)
|
285
|
-
|
573
|
-
|
Marketing
Company
sales
to IP(c)
|
874
|
-
|
1,700
|
-
|
(a)
|
These
agreements expired or terminated on December 31,
2006.
|
(b)
|
In
December 2006, Genco and Marketing Company, and AERG and Marketing
Company, entered into new power supply agreements whereby Genco
and AERG
sell and Marketing Company purchases all the capacity available
from
Genco’s and AERG’s generation fleets and such amount of associated energy
commencing on January 1, 2007.
|
(c)
|
In
accordance with the January 2006 ICC order, discussed in Note
2 – Rate and
Regulatory Matters, an auction was held in September 2006 to
procure power
for CIPS, CILCO and IP after their previous power supply contracts
expired
on December 31, 2006. Through the auction, Marketing Company
contracted
with CIPS, CILCO and IP to provide power for their customers.
See also
Note 3 – Rate and Regulatory Matters under Part II, Item 8 of the Form
10-K for further details of the power procurement auction in
Illinois. See
Note 2 – Rate and Regulatory Matters for a discussion of potential future
changes in the Illinois power procurement process as a result
of the
electric settlement agreement reached among key stakeholders
in July
2007.
|
Joint
Dispatch Agreement
UE,
CIPS and Genco mutually consented
to waive the one-year termination notice requirement of the JDA and agreed
to
terminate it on December 31, 2006. This action with respect to the JDA
was
accepted by FERC in September 2006.
The
following table presents the amount of gigawatthour sales under the JDA
for the
three months and six months ended June 30, 2006:
Three
Months
|
Six
Months
|
|
UE
sales to Genco
|
2,639
|
5,434
|
Genco
sales to UE
|
1,111
|
1,717
|
43
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:
Three
Months
|
Six
Months
|
|
UE
|
$25
|
$58
|
Genco
|
5
|
17
|
Total
|
$30
|
$75
|
Money
Pools
See
Note 3 - Credit Facilities and
Liquidity for a discussion of affiliate borrowing arrangements.
Intercompany
Promissory Notes
Genco’s
subordinated note payable to CIPS associated with the transfer in 2000
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 $2 million (2006 - $3 million) and $5 million (2006 -
$7
million) for the three months and six months ended June 30, 2007 and 2006,
respectively.
CILCORP
has been granted authority by
FERC in a 2006 order to borrow up to $250 million directly from Ameren.
The
outstanding borrowings were zero and $156 million at June 30, 2007 and
2006,
respectively. The average interest rate on these borrowings was 6.9% and
5.6%
for the three months and six months ended June 30, 2007, respectively (2006
–
4.6% and 4.3%, respectively). CILCORP recorded interest expense of less
than $1
million (2006 - $2 million) and less than $1 million (2006 - $4 million)
for
these borrowings for the three months and six months ended June 30, 2007,
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,
2007 and 2006. It is based primarily on the agreements discussed above
and in
Note 13 – Related Party Transactions under Part II, Item 8 of the Form 10-K, and
the money pool arrangements discussed above in Note 3 - Credit Facilities
and
Liquidity of this report.
Three
Months
|
Six
Months
|
||||||||||
Agreement
|
UE
|
CIPS
|
Genco
|
CILCORP(a)
|
IP
|
UE
|
CIPS
|
Genco
|
CILCORP(a)
|
IP
|
Operating
Revenues:
|
|||||||||||||||||||||||||||||||||||||||||
Genco
and AERG power supply agreements
|
2007
|
$ | (b) | $ | (b) | $ |
182
|
$ |
62
|
$ | (b) | $ | (b) | $ | (b) | $ |
393
|
$ |
134
|
$ | (b) | ||||||||||||||||||||
with
Marketing Company
|
|||||||||||||||||||||||||||||||||||||||||
Ancillary
service agreement with CIPS, CILCO and IP
|
2007
|
4
|
(b)
|
(b)
|
(b)
|
(b)
|
8
|
(b)
|
(b)
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
|
|||||||||||||||||||||||||||||||||||||||||
Power
supply agreement with Marketing Company -
|
|||||||||||||||||||||||||||||||||||||||||
expired
December 31, 2006
|
2006
|
(b)
|
(b)
|
194
|
1
|
(b)
|
(b)
|
(b)
|
389
|
5
|
(b)
|
||||||||||||||||||||||||||||||
|
|||||||||||||||||||||||||||||||||||||||||
UE
and Genco gas
|
2007
|
(c)
|
(b)
|
(b)
|
(b)
|
(b)
|
(c)
|
(b)
|
(b)
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
transportation
agreement
|
2006
|
(c)
|
(b)
|
(b)
|
(b)
|
(b)
|
(c)
|
(b)
|
(b)
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
JDA
– terminated
December
31, 2006
|
2006
|
49
|
(b)
|
27
|
(b)
|
(b)
|
121
|
(b)
|
46
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
Total
Operating Revenues
|
2007 | $ | 4 | $ |
(b)
|
$ | 182 | $ |
62
|
$ |
(b)
|
$ | 8 | $ |
(b)
|
$ | 393 | $ |
134
|
$ |
(b)
|
||||||||||||||||||||
2006
|
49
|
(b)
|
221
|
1
|
(b)
|
121
|
(b)
|
435
|
5
|
(b)
|
|||||||||||||||||||||||||||||||
Fuel
and Purchased Power:
|
|||||||||||||||||||||||||||||||||||||||||
CIPS,
CILCO and IP agreements with Marketing
|
2007
|
$ | (b) | $ |
36
|
$ | (b) | $ |
19
|
$ |
57
|
$ | (b) | $ |
78
|
$ | (b) | $ |
38
|
$ |
112
|
||||||||||||||||||||
Company
(auction)
|
|||||||||||||||||||||||||||||||||||||||||
Ancillary
service agreement with UE
|
2007
|
(b)
|
2
|
(b)
|
(c)
|
2
|
(b)
|
3
|
(b)
|
1
|
4
|
||||||||||||||||||||||||||||||
Ancillary
service agreement with Marketing Company
|
2007
|
(b)
|
1
|
(b)
|
(c)
|
1
|
(b)
|
2
|
(b)
|
1
|
2
|
||||||||||||||||||||||||||||||
|
|||||||||||||||||||||||||||||||||||||||||
JDA
– terminated
December
31, 2006
|
2006
|
27
|
(b)
|
49
|
(b)
|
(b)
|
46
|
(b)
|
121
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
Power
supply agreement with Marketing Company -
|
|||||||||||||||||||||||||||||||||||||||||
expired
December 31, 2006
|
2006
|
(b)
|
111
|
(b)
|
(c)
|
(b)
|
(b)
|
219
|
(b)
|
(c)
|
(b)
|
||||||||||||||||||||||||||||||
|
|||||||||||||||||||||||||||||||||||||||||
Executory
tolling agreement
|
2007
|
(b)
|
(b)
|
(b)
|
8
|
(b)
|
(b)
|
(b)
|
(b)
|
20
|
(b)
|
||||||||||||||||||||||||||||||
with
Medina Valley
|
2006
|
(b)
|
(b)
|
(b)
|
7
|
(b)
|
(b)
|
(b)
|
(b)
|
20
|
(b)
|
||||||||||||||||||||||||||||||
UE and Genco gas | 2007 |
(b)
|
(b)
|
(c)
|
(b) |
(b)
|
(b)
|
(b)
|
(c)
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
transportation
agreement
|
2006 |
(b)
|
(b)
|
(c)
|
(b) |
(b)
|
(b)
|
(b)
|
(c)
|
(b) |
(b)
|
||||||||||||||||||||||||||||||
Total
Fuel and Purchased
|
2007 |
$
(b)
|
$ |
39
|
$ |
(c)
|
$ | 27 | $ |
60
|
$ (b)
|
$ |
83
|
$
(c)
|
$ | 60 | $ |
118
|
|||||||||||||||||||||||
Power | 2006 |
27
|
111
|
49
|
7
|
(b)
|
46
|
219
|
121
|
20
|
(b)
|
44
Three
Months
|
Six
Months
|
Agreement
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
UE
|
CIPS
|
Genco
|
CILCORP(a) |
IP
|
|||||||||||||||||||||||||||||||
Other
Operating Expense:
|
|||||||||||||||||||||||||||||||||||||||||
Ameren
Services support
|
2007
|
$ |
32
|
$ |
11
|
$ |
6
|
$ |
12
|
$ |
17
|
$ |
68
|
$ |
23
|
$ |
12
|
$ |
25
|
$ |
36
|
||||||||||||||||||||
services
agreement
|
2006
|
36
|
13
|
6
|
13
|
19
|
69
|
24
|
11
|
25
|
36
|
||||||||||||||||||||||||||||||
Ameren
Energy support
|
2007
|
2
|
(b)
|
(c)
|
(b)
|
(b)
|
5
|
(b)
|
(c)
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
services
agreement
|
2006
|
2
|
(b)
|
(c)
|
(b)
|
(b)
|
4
|
(b)
|
1
|
(b)
|
(b)
|
||||||||||||||||||||||||||||||
AFS
support services
|
2007
|
1
|
1
|
(c)
|
(c)
|
1
|
3
|
1
|
1
|
1
|
1
|
||||||||||||||||||||||||||||||
agreement |
2006
|
1
|
1
|
(c)
|
1
|
(c)
|
2
|
1
|
1
|
1
|
1
|
||||||||||||||||||||||||||||||
Insurance
premiums
|
2007
|
5
|
(b)
|
1
|
1
|
(b)
|
9
|
(b)
|
2
|
1
|
(b)
|
||||||||||||||||||||||||||||||
Total
Other Operating
|
2007
|
$ |
40
|
$ |
12
|
$ |
7
|
$ |
13
|
$ |
18
|
$ |
85
|
$ |
24
|
$ |
15
|
$ |
27
|
$ |
37
|
||||||||||||||||||||
Expenses |
2006
|
39
|
14
|
6
|
14
|
19
|
75
|
25
|
13
|
26
|
37
|
||||||||||||||||||||||||||||||
Interest
expense (income) from money pool borrowings
|
2007
|
$ |
-
|
$ | (c) | $ |
2
|
$ | (c) | $ | (c) | $ |
-
|
$ | (c) | $ |
4
|
$ | (c) | $ | (c) | ||||||||||||||||||||
(advances)
|
2006
|
(c)
|
(1) |
3
|
1
|
(c)
|
(c)
|
(1) |
5
|
3
|
1
|
(a)
|
Amounts
represent CILCORP and CILCO
activity.
|
(b)
|
Not
applicable.
|
(c) | Amount less than $1 million. |
NOTE
8 – COMMITMENTS AND CONTINGENCIES
We
are
involved in legal, tax and regulatory proceedings before various courts,
regulatory commissions, and governmental agencies with respect to matters
that
arise in the ordinary course of business, 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 a material adverse 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 13 – Related Party Transactions, and Note 14 –
Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See
also
Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and
Regulatory Matters and Note
7
–
Related Party Transactions in this report.
Callaway
Nuclear Plant
The
following table presents insurance coverage at UE’s Callaway nuclear plant at
June 30, 2007. The property coverage was renewed on October 1, 2006. The
nuclear
liability coverage anniversary was January 1, 2007.
Type
and Source of Coverage
|
Maximum
Coverages
|
Maximum
Assessments for Single Incidents
|
|||||
Public
liability:
|
|||||||
American
Nuclear
Insurers
|
300
|
-
|
|||||
Pool
participation
|
10,461 | (a) | 101 | (b) | |||
$ | 10,761 | (c) | $ |
101
|
|||
Nuclear
worker liability:
|
|||||||
American
Nuclear
Insurers
|
$ | 300 | (d) | $ |
4
|
||
Property
damage:
|
|||||||
Nuclear
Electric Insurance
Ltd.
|
$ | 2,750 | (e) | $ |
24
|
||
Replacement
power:
|
|||||||
Nuclear
Electric Insurance
Ltd.
|
$ | 490 | (f) | $ |
9
|
(a)
|
Provided
through mandatory participation in an industry-wide retrospective
premium
assessment program.
|
(b)
|
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.
|
(c)
|
Limit
of liability for each incident under Price-Anderson. This limit
is subject
to change to account for the effects of inflation and changes
in the
number of licensed reactors.
|
(d)
|
Industry
limit for potential liability for worker tort claims filed for
bodily
injury caused by a nuclear energy accident. Effective January
1, 1998,
this program was modified to provide coverage to all workers
whose
nuclear-related employment began on or after the commencement
date of
reactor operations.
|
(e)
|
Provides
for $500 million in property damage and decontamination, excess
property
insurance, and premature decommissioning coverage up to $2.25 billion
for losses in excess of the $500 million primary
coverage.
|
(f)
|
Provides
the replacement power cost insurance in the event of a prolonged
accidental outage at a nuclear plant. 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.
|
45
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. The limit of liability and the maximum potential annual
payments are adjusted at least every five years for inflation 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.
Subsequent
to the terrorist attacks on September 11, 2001, both American Nuclear Insurers
and Nuclear Electric Insurance Ltd. confirmed that terrorist attacks would
be
covered under their policies, subject to applicable policy limits. Both
companies, however, revised their policy terms to include an industry aggregate
for all “non-certified” terrorist acts as defined by the Terrorism Risk
Insurance Act of 2002, which was renewed in 2005. The non-certified American
Nuclear Insurers nuclear liability cap is a $300 million shared industry
aggregate during the policy period. The aggregate for all Nuclear Electric
Insurance Ltd. policies which apply to non-certified property claims within
a
12-month period is $3.2 billion, plus any amounts available through reinsurance
or indemnity from an outside source.
If
losses
from a nuclear incident at the Callaway nuclear plant exceed the limits
of, or
are not subject to, insurance, or if coverage is unavailable, UE is at
risk for
any uninsured losses. If a serious nuclear incident occurred, it could
have a
material adverse effect on Ameren’s and UE’s results of operations, financial
position, or liquidity.
Other
Obligations
To
supply
a portion of the fuel requirements of our generating plants, we have entered
into various long-term commitments for the procurement of coal, natural
gas and
nuclear fuel. In addition, we have entered into various long-term commitments
for the purchase of electricity and natural gas for distribution. For a
complete
listing of our obligations and commitments, see Note 14 – Commitments and
Contingencies under Part II, Item 8 of the Form 10-K.
As
of
June 30, 2007, the commitments for the procurement of natural gas have
materially changed from amounts previously disclosed as of December 31,
2006.
The following table presents the total estimated natural gas purchase
commitments at June 30, 2007:
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter(a)
|
||||||||||||||||||
Ameren(b)
|
$ |
351
|
$ |
495
|
$ |
343
|
$ |
227
|
$ |
200
|
$ |
1,961
|
|||||||||||
UE
|
41
|
71
|
51
|
32
|
26
|
56
|
|||||||||||||||||
CIPS
|
64
|
110
|
78
|
55
|
39
|
69
|
|||||||||||||||||
Genco
|
15
|
19
|
8
|
8
|
8
|
13
|
|||||||||||||||||
CILCORP/CILCO
|
88
|
127
|
84
|
47
|
56
|
839 | (c) | ||||||||||||||||
IP
|
137
|
161
|
119
|
84
|
70
|
983 | (c) |
(a)
|
Commitments
for natural gas are until 2017.
|
(b)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries
and
intercompany eliminations.
|
(c)
|
Commitments
for natural gas purchases for CILCO and IP include projected
synthetic
natural gas purchases pursuant to a 20-year supply contract beginning
in
April 2011.
|
As
of
June 30, 2007, the commitments for the procurement of nuclear fuel have
materially changed from amounts previously disclosed as of December 31,
2006.
The following table presents the total estimated nuclear fuel purchase
commitments at June 30, 2007:
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter(a)
|
||||||||||||||||||
Ameren/UE
|
$ |
51
|
$ |
81
|
$ |
37
|
$ |
113
|
$ |
33
|
$ |
139
|
(a)
|
Commitments
for nuclear fuel are until 2020.
|
At
this
time, UE does not expect to require new baseload generation capacity until
at
least 2018. However, due to the significant time required to plan, acquire
permits for and build a baseload power plant, UE is actively studying future
plant alternatives, including those that would use coal or nuclear
fuel. During the three months ended June 30, 2007, UE entered into a
commitment to purchase heavy forgings needed to construct a nuclear plant.
This
commitment does not mean a decision has been made to build a nuclear plant.
The
purpose of entering into the forgings purchase commitment was to secure
access
to heavy forgings, which are long lead-time materials, in the event that
UE
decides to build a nuclear plant. As of June 30, 2007, UE’s commitments to
purchase heavy forgings totaled $88 million through 2010 ($3.5 million
in 2007,
$6.5 million in 2008, $7.5 million in 2009 and $70.5 million in
2010).
46
As
part
of the electric settlement agreement in Illinois, the Ameren Illinois Utilities
entered into financial contracts with Marketing Company to lock-in prices
for
400 to 1,000 megawatts annually of their baseload power requirements from
2008
to 2012 at relevant market prices. These contracts have been executed but
are
not effective until enactment of Proposed Legislation by the Illinois governor.
See Note 2 – Rate and Regulatory Matters for information on the electric
agreement in Illinois.
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, natural gas storage plants, and natural gas
transmission and distribution facilities, our activities involve compliance
with
diverse laws and regulations. These laws and regulations address noise,
emissions, and impacts to air and water, protected and cultural resources
(such
as wetlands, endangered species, and archeological and historical resources),
and chemical and waste handling. Our activities often require complex and
lengthy processes as we obtain approvals, 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 require significant reductions
in
these emissions from UE, Genco, AERG 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. Although the federal rules
mandate a specific 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 has enacted rules to implement the federal Clean Air Interstate
Rule
program that will reduce the number of NOx allowances automatically
allocated to Genco’s, AERG’s and EEI’s plants; however, it is anticipated that
the rules will not be finalized until the third quarter of 2007. As a result
of
the Illinois rules, Genco, AERG and EEI would need to procure allowances
and
install pollution control equipment in order to continue to
operate.
The
Missouri Department of Natural Resources formally proposed rules to implement
the federal Clean Air Mercury and Clean Air Interstate Rules in November
2006.
These rules substantially follow the federal rules. The Missouri Air
Conservation Commission approved the rules at their February 2007 meeting.
The
rules became effective after publication in the Missouri Register in April
2007.
When fully implemented, it is estimated that these rules will reduce mercury
emissions 81% by 2018 and reduce NOx emissions
30% and
SO2 emissions
75% by 2015.
Illinois
has adopted rules for mercury that are significantly stricter than the
federal
rules. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an
agreement that was incorporated into Illinois’ mercury regulations. Under the
regulations, Illinois generators may defer until 2015 the requirement to
reduce
mercury emissions by 90% in exchange for accelerated installation of
NOx and SO2 controls. Genco, AERG and EEI will begin
installing equipment designed to reduce mercury emissions in 2009. When
fully
implemented, it is estimated that these rules will reduce mercury emissions
90%,
NOx emissions 50% and SO2 emissions 70% by 2015 in
Illinois.
The
table
below presents estimated capital costs based on current technology to comply
with both the federal Clean Air Interstate Rule and Clean Air Mercury Rule
through
2016 and related state implementation plans. The estimates described below
could
change depending upon additional federal or state requirements, new technology,
variations in costs of material or labor, or alternative compliance strategies,
among other reasons. The timing of estimated capital costs may also be
influenced by whether emission allowances are used to comply with the proposed
rules, thereby deferring capital investment.
2007
|
2008
– 2011
|
2012
- 2016
|
Total
|
|
UE(a)
|
$
110
|
$ 630-830
|
$ 910-1,180
|
$ 1,650-2,120
|
Genco
|
110
|
820-1,060
|
180-
260
|
1,110-1,430
|
CILCO
(AERG)
|
100
|
185-240
|
95-
140
|
380-480
|
EEI
|
10
|
185-240
|
165-
220
|
360-470
|
Ameren
|
$
330
|
$ 1,820-2,370
|
$ 1,350-1,800
|
$ 3,500-4,500
|
(a)
|
UE’s
expenditures are expected to be recoverable in rates over
time.
|
Illinois
and Missouri must also develop attainment plans to meet the federal eight-hour
ozone ambient standard, the federal fine particulate ambient standard and
the
Clean Air Visibility rule. Both states have filed ozone attainment plans
for the
St. Louis area. The state attainment plans for fine particulate must be
submitted to the EPA by April 2008 and the plans for the Clean Air
Visibility rule must be submitted to the EPA by December 2007. The costs 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. Illinois is planning
to
impose additional requirements beyond the Clean Air Interstate
47
Rule
as
part of the attainment plans for ozone and fine particulate. At this time,
we
are unable to determine the impact such state actions would have on our
results
of operations, financial position, or liquidity.
Emission
Allowances
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 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 was applied to the eastern third of Missouri, where
UE’s
coal-fired power plants are located, beginning in 2007. Our generating
facilities are expected to comply with the NOx limits through the use
and purchase of allowances or through the application of pollution control
technology, including low-NOx burners, over-fire air systems,
combustion optimization, rich-reagent injection, selective noncatalytic
reduction, and selective catalytic reduction systems.
The
following table presents the SO2 and
NOx emission
allowances
held and the related SO2 and
NOx book
values that
are carried as intangible assets as of June 30, 2007.
SO2(a)
|
NOx(b)
|
Book
Value
|
|
UE
|
1.633
|
21,994
|
$ 58
|
Genco
|
0.637
|
14,746
|
64
|
CILCO
(AERG)
|
0.304
|
3,419
|
2
|
EEI
|
0.300
|
4,690
|
9
|
Ameren
|
2.874
|
44,849
|
206(c)
|
(a)
|
Vintages
are from 2007 to 2016. Each company possesses additional allowances
for
use in periods beyond 2016. Units are in millions of SO2
allowances (currently one allowance equals one ton
emitted).
|
(b)
|
Vintages
are from 2007 to 2008. Units are in NOx allowances (one
allowance equals one ton emitted).
|
(c)
|
Includes
value assigned to AERG and EEI allowances as a result of purchase
accounting of $73 million.
|
UE,
Genco, CILCO and EEI expect to use a substantial portion of the SO2 and
NOx allowances
for
ongoing operations. New environmental regulations, including the Clean
Air
Interstate Rule, the timing of the installation of pollution control equipment
and the level of operations will have a significant impact on the amount
of
allowances actually required for ongoing operations. The Clean Air Interstate
Rule requires a reduction in SO2 emissions
by
increasing the ratio of Acid Rain Program allowances 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. In order to accommodate this change in surrender ratio and to
comply
with the federal and state regulations, UE, Genco, AERG and EEI expect
to
install control technology designed to further reduce SO2
emissions.
Renewable
Energy
As
part
of the electric agreement in Illinois that is subject to enactment of Proposed
Legislation, a minimum percentage of CIPS’, CILCO’s and IP’s total supply to
serve the load of eligible retail customers to be procured in each of the
following years would be committed to being generated from renewable energy
resources, subject to limits on customer rate impacts:
·
|
at
least 2% by June 1, 2008;
|
·
|
at
least 4% by June 1, 2009, increasing by at least 1% each year
thereafter
through June 1, 2015; and
|
·
|
increasing
by at least 1.5% each year after June 1, 2015 to at least 25%
by June 1,
2025.
|
To
the
extent available, at least 75% of the renewable energy should come from
wind
generation according to the agreement. A provision for full and timely
cost
recovery of the cost of the commitments is also included in the agreement.
We
are in the process of determining our compliance plans. See Note 2 – Rate and
Regulatory Matters for information on the electric settlement agreement
in
Illinois.
Missouri
has enacted voluntary goals for total power to be supplied from renewable
energy
sources while the federal government continues to consider mandatory
thresholds.
Global
Climate
Future
initiatives regarding greenhouse gas emissions and global warming are the
subjects of much debate. As a result of our diverse fuel portfolio, our
contribution to greenhouse gases varies. Coal-fired power plants are significant
sources of carbon dioxide, a principal greenhouse gas. Six electric power
sector
trade associations, including the Edison Electric Institute, of which Ameren
is
a member, and the TVA, signed a Memorandum of Understanding (MOU) with
48
the
DOE
in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity
from the utility sector between 2002 and 2012.
Ameren has undertaken various initiatives to comply with the MOU, including
enhanced generation at our nuclear and hydroelectric power plants, increased
efficiency measures at our coal-fired units, and investments in renewable
energy
and carbon sequestration projects.
In
April
2007, the U.S. Supreme Court issued a decision that determined that the
EPA has
authority to regulate carbon dioxide and other greenhouse gases from automobiles
as “air pollutants” under the Clean Air Act. The Supreme Court sent the case
back to the EPA, which must conduct a rulemaking to determine whether greenhouse
gas emissions contribute to climate change “which may reasonably be anticipated
to endanger public health or welfare.” Unless the U.S. Congress enacts
legislation directing otherwise, the EPA could begin to regulate such
emissions.
The
impact of future initiatives related to greenhouse gas emissions and global
warming on us are unknown. Although compliance costs are unlikely in the
near
future, our costs of complying with any mandated federal greenhouse gas
program
could have a material impact on our future results of operations, financial
position, or liquidity.
New
Source Review
The
EPA has been conducting an
enforcement initiative 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 (NSR) 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 2007, the U.S. Supreme Court
in Environmental Defense v. Duke Energy Corp., issued a decision which
effectively reduced the statutory defenses available to NSR and Prevention
of
Significant Deterioration (PSD) claims. The key issue before the Supreme
Court
was whether EPA requirements to obtain permits under the NSR and PSD programs
are triggered when a “modification” at an industrial facility results in an
increase in an hourly emissions rate, as upheld by the U.S. Court of Appeals
for
the Fourth Circuit, or in total annual emissions, as asserted by environmental
groups. The U.S. Supreme Court found that the NSR and PSD regulations can
be
triggered by either an hourly or annual increase in the emissions. The
Supreme
Court decision did not address other potential defenses or potential exceptions
under the NSR and PSD programs.
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. In December 2006, the EPA issued
a second Section 114(a) request to Genco regarding projects at the Newton
facility. All of these facilities are coal-fired power plants. We are currently
in discussions with the EPA and interested stakeholders regarding resolution
of
these matters, but we are unable to predict the outcome of these discussions.
Resolution of these matters could have a material adverse impact on our
future
results of operations, financial position, or liquidity.
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 have contractually agreed to indemnify Genco and AERG for remediation
costs associated with preexisting environmental contamination at the transferred
sites.
As
of
June 30, 2007, 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, 2007, CIPS, CILCO and IP had recorded liabilities of
$25 million, $5 million and $78 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 in effect in Missouri a rate rider
mechanism that permits remediation costs associated with MGP sites to be
recovered from utility customers. 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
49
are
not
able to determine the maximum liability for the remediation of these sites.
As
of June 30, 2007, UE had recorded $6 million to represent its estimated
minimum
obligation for its MGP sites. UE also is responsible for four electric
sites in
Missouri that have corporate cleanup liability, most as a result of federal
agency mandates. As of June 30, 2007, UE had recorded $4 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, including Solutia,
that
former landfills and lagoons in Sauget, Illinois, may contain soil and
groundwater contamination. These sites are known as Sauget Area 2. From
about
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 (PRPs) to evaluate the extent of potential
contamination with respect to Sauget Area 2.
Sauget
Area 2 investigation activities under the oversight of the EPA are largely
completed and will be submitted to the EPA by the end of 2007. Following
this
submission, the EPA will ultimately select a remedy alternative and begin
negotiations with various PRPs to implement the selected alternative. Over
the
last several years, numerous other parties have joined the PRP group and
presumably will participate in the funding of any required remediation.
In
addition, Pharmacia Corporation and Monsanto Company have agreed to assume
the
liabilities of Solutia related to Solutia’s former chemical waste landfill in
the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy
protection.
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 $4 million at June 30, 2007, 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 actions may have on our results of operations, financial position,
or liquidity.
Polychlorinated
Biphernals Information Request
Polychlorinated
biphernals (PCBs) are
a blend of chemical compounds that were historically used in a variety
of
industrial products because of their chemical and thermal stability. In
natural
gas systems, PCBs were used as a compressor lubricant and a valve sealant,
before the sale of PCBs for these applications was banned by the EPA in
1979. On
July 18, 2007, the Ameren Illinois Utilities received a request from the
Illinois attorney general for information regarding its experiences with
PCBs in
its gas distribution system. The Ameren Illinois Utilities will respond
fully to
this information request, but we cannot predict the outcome of this
matter.
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. At the FERC’s direction, outside
experts were hired by UE to review the cause of the incident. Their reports
and
reports by FERC staff indicated 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. FERC agreed with this conclusion and rejected repair
as an
option.
The
FERC
investigation of the incident has been completed. In October 2006, the
FERC
approved a stipulation and consent agreement between UE and the FERC’s Office of
Enforcement that resolves all issues arising from an investigation that
the
FERC’s Office of Enforcement conducted into alleged violations of license
conditions and FERC regulations by UE as the licensee of the Taum Sauk
hydroelectric facility that may have contributed to the breach of the upper
reservoir. As part of the stipulation and consent agreement, UE agreed,
among
other things, (1) to pay a civil penalty of $10 million, (2) to pay $5
million
into an interest-bearing escrow account to fund project enhancements at
or near
the Taum Sauk facility, and (3) to implement and comply with a new dam
safety
program developed in connection with the settlement.
In
February 2007, UE submitted plans and an environmental report to FERC to
rebuild
the upper reservoir at its Taum Sauk Plant, assuming successful resolution
of
outstanding issues with authorities of the state of Missouri. Should the
decision be made to rebuild the Taum Sauk plant, UE would expect it to
be out of
service through at least the middle of 2009, if not longer.
UE
has accepted responsibility for
the effects of the incident. At this time, UE believes that substantially
all
50
damages
and liabilities (but not penalties) caused by the breach, plus the cost
of
rebuilding the plant, will be covered by insurance. Based on recent settlement
discussions, UE expects the total cost for clean up, damage and liabilities,
excluding costs to rebuild the facility, resulting from the Taum Sauk incident
to range from $182 million to $202 million. As of June 30, 2007, UE had
paid $82
million and accrued a $100 million liability, including costs resulting
from the FERC-approved stipulation and consent agreement discussed above,
while
expensing $31 million and recording a $151 million receivable due from
insurance companies. As of June 30, 2007, UE has received $35 million from
insurance companies, which reduced the insurance receivable balance to
$116
million. As of June 30, 2007, UE had a $27 million receivable due from
insurance
companies related to rebuilding the facility. Under UE’s insurance policies, all
claims by or against UE are subject to review by its insurance
carriers.
In
December 2006, the state of
Missouri, through its attorney general, and 10 business owners filed separate
lawsuits regarding the Taum Sauk breach that are currently pending in the
Missouri circuit court in Reynolds County. The attorney general’s suit alleges
negligence, violations of the Missouri Clean Water Act and various other
statutory and common law claims. The business owners’ suit contains similar
allegations and seeks damages relating to business losses and lost profit.
Both
suits seek unspecified punitive damages. In May 2007, the Missouri Department
of
Natural Resources’ petition to intervene as a plaintiff in the attorney
general’s lawsuit was denied.
See
Note 2 – Rate and Regulatory
Matters for information on the MoPSC’s Taum Sauk investigation.
Until
the reviews conducted by state
authorities have concluded, litigation has been resolved, the insurance
review
is completed, a final decision about whether the plant will be rebuilt
is made,
and future regulatory treatment for the facility 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 189
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, 2007, the average number of parties
was
70.
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 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 or CILCO has contractually agreed to
indemnify
Genco or 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 awarded, typically would be shared among the
named
defendants.
From
April 1, 2007, through June 30,
2007, five additional asbestos-related lawsuits were filed against UE,
CIPS,
CILCO and IP, mostly in the Circuit Court of Madison County, Illinois.
No
lawsuits were dismissed and five were settled. The following table presents
the
status as of June 30, 2007, 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
|
334
|
31
|
185
|
141
|
2
|
45
|
159
|
Settled
|
112
|
-
|
57
|
47
|
-
|
17
|
57
|
Dismissed
|
151
|
27
|
98
|
51
|
2
|
9
|
69
|
Pending
|
71
|
4
|
30
|
43
|
-
|
19
|
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, 2007, eight 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.
IP
has a
tariff rider to recover the costs of 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
51
by
IP
from a $20 million trust fund established by IP 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.
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.
NOTE
9 – CALLAWAY NUCLEAR PLANT
Under
the
Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent
storage and disposal of spent nuclear fuel. The DOE currently charges one
mill,
or 1/10
of one cent, per
nuclear-generated kilowatthour sold for future disposal of spent fuel.
Pursuant
to this act, UE collects one mill from its electric customers for each
kilowatthour of electricity that it generates and sells from its Callaway
nuclear plant. Electric utility rates charged to customers provide for
recovery
of such costs. The DOE is not expected to have its permanent storage facility
for spent fuel available until at least 2017. UE has sufficient installed
storage capacity at its Callaway nuclear plant until 2020. It has the capability
for additional storage capacity through the licensed life of the plant.
The
delayed availability of the DOE’s disposal facility is not expected to adversely
affect the continued operation of the Callaway nuclear plant through its
currently licensed life.
Electric
utility rates charged to customers provide for the recovery of the Callaway
nuclear plant’s decommissioning costs, which include decontamination,
dismantling, and site restoration costs, over an assumed 40-year life of
the
plant, ending with the expiration of the plant’s operating license in 2024. It
is assumed that the Callaway nuclear plant site will be decommissioned
based on
immediate dismantlement method and removal from service. Ameren and UE
have
recorded an ARO
for
the Callaway nuclear plant decommissioning costs at fair value, which represents
the present value of estimated future cash outflows. Decommissioning costs
are
charged to the costs of service used to establish electric rates for UE’s
customers. These costs amounted to $7 million in each of the years 2006,
2005
and 2004. 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.
Minor tritium contamination was discovered on the Callaway nuclear plant
site in
the summer of 2006. Existing facts and regulatory requirements indicate
that
this discovery will not cause any significant increase in a decommissioning
cost
estimate when the next study is conducted. Costs collected from customers
are
deposited in an external trust fund to provide for the Callaway nuclear
plant’s
decommissioning. If the assumed return on trust assets is not earned, we
believe
that it is probable that any such earnings deficiency will be recovered
in
rates. The fair value of the nuclear decommissioning trust fund for UE’s
Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund
in
Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally
restricted. It may be used only to fund the costs of nuclear decommissioning.
Changes in the fair value of the trust fund are recorded as an increase
or
decrease to the nuclear decommissioning trust fund and to a regulatory
asset.
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, 2007 and 2006, is shown below
for the
Ameren Companies:
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Ameren:(a)
|
|||||||||||||||
Net
income
|
$ |
143
|
$ |
123
|
$ |
266
|
$ |
193
|
|||||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes
(benefit)
of $12, $5, $(3) and $(5), respectively
|
23
|
9
|
(5 | ) | (8 | ) | |||||||||
Reclassification
adjustments for (gain) included in net income, net of
taxes
of $2, $-, $9 and $2, respectively
|
(2 | ) | (1 | ) | (15 | ) | (4 | ) | |||||||
Adjustment
to pension and benefit obligation, net of taxes (benefit) of
$(1),
$-, $(2) and $-, respectively
|
(2 | ) |
-
|
-
|
-
|
||||||||||
Total
comprehensive income, net
of taxes
|
$ |
162
|
$ |
131
|
$ |
246
|
$ |
181
|
|||||||
UE:
|
|||||||||||||||
Net
income
|
$ |
81
|
$ |
92
|
$ |
119
|
$ |
143
|
|||||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes
(benefit)
of $2, $(1), $(1) and $(3), respectively
|
4
|
(1 | ) | (1 | ) | (5 | ) | ||||||||
Reclassification
adjustments for (gain) loss included in net income, net of
taxes
(benefit) of $(1) , $-, $1 and $-, respectively
|
1
|
1
|
(2 | ) |
1
|
||||||||||
Total
comprehensive income, net of taxes
|
$ |
86
|
$ |
92
|
$ |
116
|
$ |
139
|
52
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
CIPS:
|
|||||||||||||||
Net
income
|
$ |
5
|
$ |
15
|
$ |
16
|
$ |
14
|
|||||||
Unrealized
(loss) on derivative hedging instruments, net of taxes (benefit)
of
$-, $(1), $- and $(3), respectively
|
(1 | ) | (1 | ) |
-
|
(4 | ) | ||||||||
Reclassification
adjustments for (gain) included in net income, net of
taxes
of $-, $-, $- and $1, respectively
|
-
|
-
|
-
|
(1 | ) | ||||||||||
Total
comprehensive income, net
of taxes
|
$ |
4
|
$ |
14
|
$ |
16
|
$ |
9
|
|||||||
Genco:
|
|||||||||||||||
Net
income
|
$ |
17
|
$ |
2
|
$ |
60
|
$ |
8
|
|||||||
Unrealized
(loss) on derivative hedging instruments, net of taxes (benefit)
of
$-, $-, $(1) and $-, respectively
|
-
|
-
|
(2 | ) | (1 | ) | |||||||||
Reclassification
adjustments for loss included in net income, net of taxes
of
$-, $-, $- and $-, respectively
|
-
|
-
|
-
|
1
|
|||||||||||
Adjustment
to pension and benefit obligation, net of taxes (benefit) of
$(2),
$-, $(2) and $-, respectively
|
(3 | ) |
-
|
(2 | ) |
-
|
|||||||||
Total
comprehensive income, net of taxes
|
$ |
14
|
$ |
2
|
$ |
56
|
$ |
8
|
|||||||
CILCORP:
|
|||||||||||||||
Net
income
|
$ |
12
|
$ |
1
|
$ |
32
|
$ |
9
|
|||||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes
(benefit)
of $(2), $(2), $- and $(10), respectively
|
(2 | ) | (3 | ) |
1
|
(15 | ) | ||||||||
Reclassification
adjustments for (gain) loss included in net income, net of
taxes
(benefit) of $(1), $-, $1 and $-, respectively
|
1
|
-
|
(2 | ) |
-
|
||||||||||
Adjustment
to pension and benefit obligation, net of taxes of $(1), $-,
$-
and
$-, respectively
|
(1 | ) |
-
|
-
|
-
|
||||||||||
Total
comprehensive income
(loss), net of taxes
|
$ |
10
|
$ | (2 | ) | $ |
31
|
$ | (6 | ) | |||||
CILCO:
|
|||||||||||||||
Net
income
|
$ |
21
|
$ |
8
|
$ |
47
|
$ |
25
|
|||||||
Unrealized
gain (loss) on derivative hedging instruments, net of taxes
(benefit)
of $(2), $(2), $- and $(10), respectively
|
(2 | ) | (3 | ) |
1
|
(15 | ) | ||||||||
Reclassification
adjustments for (gain) included in net income, net of
taxes
of $-, $-, $1 and $-, respectively
|
-
|
-
|
(3 | ) |
-
|
||||||||||
Total
comprehensive income, net of taxes
|
$ |
19
|
$ |
5
|
$ |
45
|
$ |
10
|
|||||||
IP:
|
|||||||||||||||
Net
income
|
$ |
7
|
$ |
16
|
$ |
20
|
$ |
20
|
|||||||
Unrealized
gain on derivative hedging instruments, net of taxes of $-, $1,
$-
and $3, respectively
|
-
|
1
|
-
|
4
|
|||||||||||
Reclassification
adjustments for (gain) included in net income, net of
taxes
of $-, $1, $- and $3, respectively
|
-
|
(1 | ) |
-
|
(4 | ) | |||||||||
Total
comprehensive income, net of taxes
|
$ |
7
|
$ |
16
|
$ |
20
|
$ |
20
|
(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, 2006, and the new contribution requirements
in the Pension Protection Act of 2006, in order to maintain minimum funding
levels for Ameren’s pension plans, we do not expect future contributions to be
required until 2009, at which time we would expect a required contribution
of
$75 million to $125 million. Required contributions of $125 million to $175
million each year are also expected for 2010 and 2011. These amounts are
estimates and may change with actual stock market performance, changes
in
interest rates, any pertinent changes in government regulations, and any
voluntary contributions.
Ameren
made a contribution to its
postretirement benefit plan of $26 million in the second quarter of 2007
as
compared to $37 million in the second quarter of the prior year.
53
The
following table presents 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, 2007 and
2006:
Pension
Benefits(a)
|
Postretirement
Benefits(a)
|
||||||||||||||||||||||||||||||
Three
Months
|
Six
Months
|
Three
Months
|
Six
Months
|
||||||||||||||||||||||||||||
2007
|
2006
|
2007
|
2006
|
2007
|
2006
|
2007
|
2006
|
||||||||||||||||||||||||
Service
cost
|
$ |
15
|
$ |
15
|
$ |
31
|
$ |
31
|
$ |
4
|
$ |
5
|
$ |
10
|
$ |
11
|
|||||||||||||||
Interest
cost
|
45
|
43
|
90
|
86
|
17
|
15
|
36
|
33
|
|||||||||||||||||||||||
Expected
return on plan assets
|
(51 | ) | (49 | ) | (103 | ) | (98 | ) | (13 | ) | (11 | ) | (26 | ) | (23 | ) | |||||||||||||||
Amortization
of:
|
|||||||||||||||||||||||||||||||
Transition
obligation
|
-
|
-
|
-
|
-
|
1
|
1
|
1
|
1
|
|||||||||||||||||||||||
Prior
service cost
(benefit)
|
3
|
3
|
6
|
5
|
(2 | ) | (2 | ) | (4 | ) | (3 | ) | |||||||||||||||||||
Actuarial
loss
|
5
|
10
|
11
|
21
|
5
|
7
|
12
|
17
|
|||||||||||||||||||||||
Net
periodic benefit cost
|
$ |
17
|
$ |
22
|
$ |
35
|
$ |
45
|
$ |
12
|
$ |
15
|
$ |
29
|
$ |
36
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant
subsidiaries.
|
UE,
CIPS,
Genco, CILCORP, CILCO, IP and EEI are participants in Ameren’s plans and are
responsible for their proportional share of the pension and postretirement
costs. The following table presents the pension costs and the postretirement
benefit costs incurred for the three months and six months ended June 30,
2007
and 2006:
Pension
Costs
|
Postretirement
Costs
|
||||||||||||||||||||||||||||||
Three
Months
|
Six
Months
|
Three
Months
|
Six
Months
|
||||||||||||||||||||||||||||
2007
|
2006
|
2007
|
2006
|
2007
|
2006
|
2007
|
2006
|
||||||||||||||||||||||||
Ameren
|
$ |
17
|
$ |
22
|
$ |
35
|
$ |
45
|
$ |
12
|
$ |
15
|
$ |
29
|
$ |
36
|
|||||||||||||||
UE
|
10
|
13
|
20
|
26
|
6
|
8
|
15
|
19
|
|||||||||||||||||||||||
CIPS
|
2
|
3
|
4
|
6
|
1
|
2
|
3
|
4
|
|||||||||||||||||||||||
Genco
|
1
|
1
|
2
|
3
|
1
|
1
|
2
|
2
|
|||||||||||||||||||||||
CILCORP
|
2
|
3
|
5
|
6
|
1
|
1
|
3
|
4
|
|||||||||||||||||||||||
IP
|
1
|
2
|
3
|
4
|
3
|
3
|
6
|
7
|
|||||||||||||||||||||||
EEI
|
1
|
-
|
1
|
-
|
-
|
-
|
-
|
-
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant
subsidiaries.
|
NOTE
12 – SEGMENT INFORMATION
Ameren
has three reportable segments: Missouri Regulated, Illinois Regulated and
Non-rate-regulated Generation. The Missouri Regulated segment for Ameren
includes all the operations of UE’s business as described in Note 1 – Summary of
Significant Accounting Policies, except for UE’s 40% interest in EEI and other
non-rate regulated activities, which are included in Other. The Illinois
Regulated segment for Ameren consists of the regulated electric and gas
transmission and distribution businesses of CIPS, CILCO, and IP, as described
in
Note 1 – Summary of Significant Accounting Policies. The Non-rate-regulated
Generation segment for Ameren primarily consists of the operations or activities
of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company.
Other
primarily includes Ameren parent company activities and the leasing activities
of CILCORP, AERG, Resources Company, and CIPSCO Investment Company.
UE
has
one reportable segment: Missouri Regulated. The Missouri Regulated segment
for
UE includes all the operations of UE’s business as described in Note 1 – Summary
of Significant Accounting Policies, except for UE’s 40%
interest in EEI and other non-rate-regulated activities, which are included
in
Other.
CILCORP
and CILCO have two reportable
segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois
Regulated segment for CILCORP and CILCO consists of the regulated electric
and
gas transmission and distribution businesses of CILCO. The Non-rate-regulated
Generation segment for CILCORP and CILCO consists of the generation business
of
AERG. Other for CILCORP and CILCO comprises leveraged lease investments,
parent
company activity, and minor activities not reported in the Illinois Regulated
or
Non-rate-regulated Generation segments for CILCORP.
54
The
following table presents information about the reported revenues and net
income
of Ameren for the three months and six months ended June 30, 2007 and 2006,
and
total assets as of June 30, 2007 and December 31, 2006.
Three
Months
|
Missouri
Regulated
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
Other
|
Intersegment
Eliminations
|
Consolidated
|
|||||||||||||||||
2007:
|
|||||||||||||||||||||||
External
revenues
|
$ |
686
|
$ |
747
|
$ |
290
|
$ |
-
|
$ |
-
|
$ |
1,723
|
|||||||||||
Intersegment
revenues
|
11
|
6
|
124
|
10
|
(151 | ) |
-
|
||||||||||||||||
Net
income(a)
|
66
|
19
|
56
|
2
|
-
|
143
|
|||||||||||||||||
2006:
|
|||||||||||||||||||||||
External
revenues
|
$ |
652
|
$ |
681
|
$ |
208
|
$ |
9
|
$ |
-
|
$ |
1,550
|
|||||||||||
Intersegment
revenues
|
58
|
6
|
191
|
6
|
(261 | ) |
-
|
||||||||||||||||
Net
income(a)
|
78
|
33
|
13
|
(1 | ) |
-
|
123
|
||||||||||||||||
Six
Months
|
|||||||||||||||||||||||
2007:
|
|||||||||||||||||||||||
External
revenues
|
$ |
1,324
|
$ |
1,801
|
$ |
608
|
$ |
9
|
$ |
-
|
$ |
3,742
|
|||||||||||
Intersegment
revenues
|
23
|
13
|
257
|
20
|
(313 | ) |
-
|
||||||||||||||||
Net
income(a)
|
89
|
48
|
126
|
3
|
-
|
266
|
|||||||||||||||||
2006:
|
|||||||||||||||||||||||
External
revenues
|
$ |
1,210
|
$ |
1,665
|
$ |
447
|
$ |
28
|
$ |
-
|
$ |
3,350
|
|||||||||||
Intersegment
revenues
|
136
|
8
|
382
|
18
|
(544 | ) |
-
|
||||||||||||||||
Net
income (loss)(a)
|
113
|
42
|
40
|
(2 | ) |
-
|
193
|
||||||||||||||||
As
of June 30, 2007:
|
|||||||||||||||||||||||
Total
assets
|
$ |
10,738
|
$ |
6,370
|
$ |
3,838
|
$ |
1,064
|
$ | (1,479 | ) | $ |
20,531
|
||||||||||
As
of December 31, 2006:
|
|||||||||||||||||||||||
Total
assets
|
10,251
|
6,226
|
3,612
|
1,161
|
(1,672 | ) |
19,578
|
(a)
|
Represents
net income available to common shareholders; 100% of CILCO’s preferred
stock dividends are included in the Illinois Regulated
segment.
|
The
following table presents information about the reported revenues and net
income
of UE for the three months and six months ended June 30, 2007 and 2006,
and
total assets as of June 30, 2007 and December 31, 2006.
Three
Months
|
Missouri
Regulated
|
Other
(a)
|
Consolidated
UE
|
||||||||
2007:
|
|||||||||||
Revenues
|
$ |
697
|
$ |
-
|
$ |
697
|
|||||
Net
income(b)
|
66
|
13
|
79
|
||||||||
2006:
|
|||||||||||
Revenues
|
$ |
710
|
$ |
-
|
$ |
710
|
|||||
Net
income(b)
|
78
|
12
|
90
|
||||||||
Six
Months
|
|||||||||||
2007:
|
|||||||||||
Revenues
|
$ |
1,347
|
$ |
-
|
$ |
1,347
|
|||||
Net
income(b)
|
89
|
27
|
116
|
||||||||
2006:
|
|||||||||||
Revenues
|
$ |
1,346
|
$ |
-
|
$ |
1,346
|
|||||
Net
income(b)
|
113
|
27
|
140
|
||||||||
As
of June 30, 2007:
|
|||||||||||
Total
assets
|
$ |
10,738
|
$ |
29
|
$ |
10,767
|
|||||
As
of December 31, 2006:
|
|||||||||||
Total
assets
|
10,251
|
36
|
10,287
|
(a)
|
Includes
40% interest in EEI and other non-rate-regulated
activities.
|
(b)
|
Represents
net income available to the common shareholder
(Ameren).
|
55
The
following table presents information about the reported revenues and net
income
of CILCORP for the three months and six months ended June 30, 2007 and
2006, and
total assets as of June 30, 2007 and December 31, 2006.
Three
Months
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
CILCORP
Other
|
Intersegment
Eliminations
|
Consolidated
CILCORP
|
||||||||||||||
2007:
|
|||||||||||||||||||
External
revenues
|
$ |
161
|
$ |
62
|
$ |
-
|
$ |
-
|
$ |
223
|
|||||||||
Intersegment
revenues
|
-
|
1
|
-
|
(1 | ) |
-
|
|||||||||||||
Net
income(a)
|
7
|
5
|
-
|
-
|
12
|
||||||||||||||
2006:
|
|||||||||||||||||||
External
revenues
|
$ |
137
|
$ |
9
|
$ |
-
|
$ |
-
|
$ |
146
|
|||||||||
Intersegment
revenues
|
-
|
44
|
-
|
(44 | ) |
-
|
|||||||||||||
Net
income(a)
|
3
|
1
|
(3 | ) |
-
|
1
|
|||||||||||||
Six
Months
|
|||||||||||||||||||
2007:
|
|||||||||||||||||||
External
revenues
|
$ |
395
|
$ |
138
|
$ |
-
|
$ |
-
|
$ |
533
|
|||||||||
Intersegment
revenues
|
-
|
2
|
-
|
(2 | ) |
-
|
|||||||||||||
Net
income(a)
|
14
|
18
|
-
|
-
|
32
|
||||||||||||||
2006:
|
|||||||||||||||||||
External
revenues
|
$ |
370
|
$ |
18
|
$ |
-
|
$ |
-
|
$ |
388
|
|||||||||
Intersegment
revenues
|
-
|
85
|
-
|
(85 | ) |
-
|
|||||||||||||
Net
income(a)
|
11
|
1
|
(3 | ) |
-
|
9
|
|||||||||||||
As
of June 30, 2007:
|
|||||||||||||||||||
Total
assets(b)
|
$ |
1,174
|
$ |
1,376
|
$ |
4
|
$ | (194 | ) | $ |
2,360
|
||||||||
As
of December 31, 2006:
|
|||||||||||||||||||
Total
assets(b)
|
1,208
|
1,246
|
4
|
(217 | ) |
2,241
|
(a)
|
Represents
net income available to the common shareholder (Ameren); 100%
of CILCO’s
preferred stock dividends are included in the Illinois Regulated
segment.
|
(b)
|
Total
assets for Illinois Regulated include an allocation of goodwill
and other
purchase accounting amounts related to CILCO that are recorded
at CILCORP
(parent company).
|
The
following table presents information about the reported revenues and net
income
of CILCO for the three months and six months ended June 30, 2007 and 2006,
and
total assets as of June 30, 2007 and December 31, 2006.
Three
Months
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
CILCO
Other
|
Intersegment
Eliminations
|
Consolidated
CILCO
|
||||||||||||||
2007:
|
|||||||||||||||||||
External
revenues
|
$ |
161
|
$ |
62
|
$ |
-
|
$ |
-
|
$ |
223
|
|||||||||
Intersegment
revenues
|
-
|
1
|
-
|
(1 | ) |
-
|
|||||||||||||
Net
income(a)
|
7
|
13
|
-
|
-
|
20
|
||||||||||||||
2006:
|
|||||||||||||||||||
External
revenues
|
$ |
137
|
$ |
9
|
$ |
-
|
$ |
-
|
$ |
146
|
|||||||||
Intersegment
revenues
|
-
|
44
|
-
|
(44 | ) |
-
|
|||||||||||||
Net
income(a)
|
3
|
7
|
(3 | ) |
-
|
7
|
|||||||||||||
Six
Months
|
|||||||||||||||||||
2007:
|
|||||||||||||||||||
External
revenues
|
$ |
395
|
$ |
138
|
$ |
-
|
$ |
-
|
$ |
533
|
|||||||||
Intersegment
revenues
|
-
|
2
|
-
|
(2 | ) |
-
|
|||||||||||||
Net
income(a)
|
14
|
32
|
-
|
-
|
46
|
||||||||||||||
2006:
|
|||||||||||||||||||
External
revenues
|
$ |
370
|
$ |
18
|
$ |
-
|
$ |
-
|
$ |
388
|
|||||||||
Intersegment
revenues
|
-
|
85
|
-
|
(85 | ) |
-
|
|||||||||||||
Net
income(a)
|
11
|
16
|
(3 | ) |
-
|
24
|
|||||||||||||
As
of June 30, 2007:
|
|||||||||||||||||||
Total
assets
|
$ |
985
|
$ |
768
|
$ |
1
|
$ | (1 | ) | $ |
1,753
|
||||||||
As
of December 31, 2006:
|
|||||||||||||||||||
Total
assets
|
1,020
|
642
|
1
|
(22 | ) |
1,641
|
(a)
|
Represents
net income available to the common shareholder (CILCORP); 100%
of CILCO’s
preferred stock dividends are included in the Illinois Regulated
segment.
|
56
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
OVERVIEW
Ameren
Executive Summary
Ameren’s
earnings in the second quarter and first half of 2007 were favorably
affected by
higher electric margins in its non-rate-regulated electric generation
business
segment due to the replacement of below-market power sales contracts
that
expired in 2006. Those contracts were replaced with higher-priced, market-based
contracts in 2007. Electric and gas margins in the first half of 2007
in
Ameren’s Missouri and Illinois rate-regulated business segments benefited from
greater cooling and heating demand caused by favorable weather conditions.
The
earnings impact of higher power sales contract prices and favorable weather
was
reduced by a planned maintenance and refueling outage at UE’s Callaway nuclear
plant in the second quarter of 2007, higher fuel costs and increased
costs of
operating and investing in Ameren’s Missouri and Illinois rate regulated
segments, among other things.
Ameren’s
earnings in the first half of 2007 were reduced by $19 million (after
taxes), or
9 cents per share, as a result of the cost of restoration efforts associated
with severe January 2007 storms. Storm-related costs in the first half of
2006 reduced net income by an estimated $6 million (after taxes), or 3
cents per share. In addition, costs related to participation in the MISO
Day Two
Energy Market were $10 million (after taxes), or 5 cents per share, higher
in
the first half of 2007 over the same period in 2006 because of a March
2007 FERC
order that reallocated such costs among market participants retroactive
to 2005.
Ameren’s net income in the first quarter of 2007 benefited from the reversal
of
a $10
million charge (after taxes), or
5
cents
per share, originally recorded in 2006 related to funding for low-income
energy
assistance and energy efficiency programs in Illinois. These commitments
were
terminated in the first quarter of 2007 as a result of credit rating
downgrades
resulting from Illinois legislative actions during that period.
In
March
and June 2007, final rate orders were received from the MoPSC for pending
UE gas
and electric rate cases, respectively. Unfortunately, these cases, which
included important and complex issues, were litigated during a time when
UE
faced a very challenging environment as a result of unprecedented storms
in 2006
and early 2007, and the breach of the upper reservoir of the Taum Sauk
pumped-storage hydroelectric facility. Consequently, the results of UE’s
Missouri electric rate case were mixed. UE was successful on some major
issues,
such as the treatment of the expiration of the cost-based EEI power supply
contract and the full inclusion of millions of dollars of investment
in peaking
generation assets in rate base. However, the MoPSC denied UE’s request to
implement a fuel and purchased power cost recovery mechanism, extended
the
period over which UE will recover the investments in its generation fleet
and
provided a below-normal return on equity. Consequently, the cash flows
and
returns on equity in the Missouri Regulated segment and at UE, at least
in the
interim, will be below where Ameren and UE believe they should be. With
increasing fuel and purchased power costs, and lacking a pass-through
mechanism,
coupled with increased capital and operations and maintenance expenditures
on
UE’s distribution system reliability, UE expects to be entering a period
where
more frequent rate case filings will be necessary.
In
Illinois, last fall the Ameren Illinois Utilities received an electric
delivery
service rate order from the ICC. The related rehearing process was completed
this spring. The results of these rate cases did not provide the ability
to
recover the current level of operating expenses. With cost disallowances
and the
cost of service in these cases basically based on 2004 cost levels, the
return on equity for the Ameren Illinois Utilities are expected to be
less than
5% in 2007, which does not include the costs of the settlement, discussed
below,
that will not be recoverable from ratepayers. As a result of these expected
low
returns, the Ameren Illinois Utilities plan to file additional delivery
service
rate cases by the end of this year. The environment in which these cases
were
litigated was challenging because the issues with the transition to new
rates in
Illinois were significant. In July 2007, a significant step was taken
towards
resolving the transition issues with the constructive settlement on electric
rate issues among key stakeholders in Illinois. An approximately $1-billion
state-wide
rate relief package is expected to be funded by contributions of $150
million
from Ameren-affiliated companies and $851 million from other electric
utilities
and generating companies. Ameren expects earnings per share would be
reduced by
approximately 26, 11, 7 and 1 cents per share in 2007, 2008, 2009 and
2010,
respectively, should legislation passed by the Illinois General Assembly
in late
July be signed by the governor of Illinois. The Illinois settlement is
a
solution that Ameren believes provides significant benefits to the Ameren
Illinois Utilities’ customers, and addresses key stakeholders’ concerns about
how power is to be procured in Illinois in the future. Ameren believes
the
solution also provides legislative,
57
General
Ameren,
headquartered in St. Louis, Missouri, is a public utility holding company
under
PUHCA 2005 administered by FERC. Ameren’s primary assets are 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 are dependent on
distributions made to it by its subsidiaries. Ameren’s principal subsidiaries
are listed below.
·
|
UE
operates a rate-regulated electric generation, transmission
and
distribution business, and a rate-regulated natural gas transmission
and
distribution business in Missouri.
|
·
|
CIPS
operates a rate-regulated electric and natural gas transmission
and
distribution business in Illinois.
|
·
|
Genco
operates a non-rate-regulated electric generation
business.
|
·
|
CILCO,
a subsidiary of CILCORP (a holding company), operates a rate-regulated
electric and natural gas transmission and distribution business
and a
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 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.
About 90% of Ameren’s 2006 revenues were directly subject to state or federal
regulation. This regulation can have a material impact on the price we
charge
for our services. Non-rate-regulated sales are subject to market conditions
for
power. 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 for our electric utility business. We
do have
natural gas cost recovery mechanisms for our Illinois and Missouri gas
delivery
businesses and purchased power recovery mechanisms for our Illinois electric
delivery businesses. See Note 2 – Rate and Regulatory Matters to our financial
statements under Part I, Item 1, for a discussion of recently-decided
rate cases
and the comprehensive rate relief program and settlement agreement in
Illinois.
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 risk and other risks inherent in our
business.
The reliability of our power plants and transmission and distribution
systems,
the level of purchased power costs, operating and administrative costs,
and
capital investment are key factors that we seek to control to optimize
our
results of operations, financial position, and liquidity.
Ameren’s
net income increased to $143 million, or 69 cents per share, in the second
quarter of 2007 from $123 million, or 60 cents per share, in the second
quarter of 2006. Net income in the Non-rate-regulated Generation segment
in the
three months ended June 30, 2007, increased by $43 million from the prior-year
period, while net earnings in the Missouri Regulated and Illinois Regulated
segments declined by $12 million and $14 million,
respectively.
Ameren’s
net income increased to $266 million, or $1.29 per share, in the first
six
months of 2007 from $193 million, or 94 cents per share, in the first six
months of 2006. Net income increased in the Illinois Regulated and
Non-rate-regulated Generation segments by $6 million and $86 million,
respectively, in the first half of 2007 compared to the prior-year period,
while
net income in the Missouri Regulated segment decreased by $24
million.
Earnings
were favorably impacted in the second quarter and first six months of
2007 as
compared with the same periods in 2006 by:
·
|
higher
margins in the Non-rate-regulated Generation segment due to
the
replacement of below-market
|
58
|
power
sales contracts, which expired in 2006, with higher-priced
contracts;
|
·
|
favorable
weather conditions;
|
·
|
the
absence of costs in the current year periods that were incurred
in the
second quarter of the prior year related to the reservoir breach
at UE’s
Taum Sauk plant (5 cents per
share);
|
·
|
higher
delivery service rates on Illinois Regulated
sales;
|
·
|
the
lack of FERC fees related to UE’s Osage hydroelectric plant in the current
year period that were incurred in the prior year period and
the
capitalization of fees, pursuant to a MoPSC order, in the current
year
period; and
|
·
|
lower
emission allowance costs and other
factors.
|
Earnings
were negatively impacted in the second quarter and first six months of
2007 as
compared with the same periods in 2006 by:
·
|
the
cost of UE’s Callaway nuclear plant refueling and maintenance outage in
the second quarter of 2007 exceeding the cost of the unplanned
outage at
the Callaway plant in the second quarter of 2006 (9 cents per
share);
|
·
|
increased
fuel and transportation prices (5 cents per share and 8
cents per share,
respectively);
|
·
|
higher
labor and employee benefit costs (2 cents per share and
8 cents per share,
respectively);
|
·
|
increased
bad debt reserves (3 cents per share and 5 cents per
share, respectively);
|
·
|
increased
depreciation expense (2 cents per share and 7 cents per
share,
respectively); and
|
·
|
higher
financing costs (4 cents per share and 8 cents per share,
respectively).
|
In
addition to the above items affecting both periods, earnings were favorably
impacted in the first six months of 2007 as compared with the first
six months
of 2006 by the reversal of an accrual originally recorded in 2006 in
the
Illinois Regulated segment for contributions to assist customers through
the
Illinois Customer-Elect electric rate increase phase-in plan
(5
cents
per share). The commitment to make these contributions was terminated
in 2007 as
a result of credit rating agency downgrades resulting from Illinois
legislative
actions.
In
addition to the above items affecting both periods, earnings were negatively
impacted in the first six months of 2007 as compared with the first
six months
of 2006 by costs associated with electric outages caused by a severe
ice storm
in January 2007 (9 cents per share) and by a FERC order in March 2007
that
reallocated costs related to participation in the MISO Day Two Energy
Market
among market participants retroactive to 2005 (5 cents per
share).
An
increase in the number of common shares outstanding reduced Ameren’s earnings
per share in the 2007 periods compared with the 2006 periods. Per share
information presented above is based on average shares outstanding in
2006.
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, 2007 and 2006:
Three
Months
|
Six
Months
|
||||||||||||||
2007
|
2006
|
2007
|
2006
|
||||||||||||
Net
income (loss):
|
|||||||||||||||
UE(a)
|
$ |
79
|
$ |
90
|
$ |
116
|
$ |
140
|
|||||||
CIPS
|
5
|
15
|
15
|
13
|
|||||||||||
Genco
|
17
|
2
|
60
|
8
|
|||||||||||
CILCORP
|
12
|
1
|
32
|
9
|
|||||||||||
IP
|
7
|
16
|
19
|
19
|
|||||||||||
Other(b)
|
23
|
(1 | ) |
24
|
4
|
||||||||||
Ameren
net income
|
$ |
143
|
$ |
123
|
$ |
266
|
$ |
193
|
(a)
|
Includes
earnings from a non-rate-regulated 40% interest in
EEI.
|
(b)
|
Includes
earnings from non-rate-regulated operations and a 40% interest
in EEI held
by Development Company, corporate general and administrative
expenses, and
intercompany eliminations.
|
59
Below
is
a table of income statement components by segment for the three months
and six
months ended June 30, 2007 and 2006:
Missouri
Regulated
|
Illinois
Regulated
|
Non-rate-regulated
Generation
|
Other
/ Intersegment
Eliminations
|
Total
|
|||||||||||||||
Three
Months 2007:
|
|||||||||||||||||||
Electric
margin
|
$ |
494
|
$ |
207
|
$ |
251
|
$ | (15 | ) | $ |
937
|
||||||||
Gas
margin
|
14
|
64
|
-
|
(2 | ) |
76
|
|||||||||||||
Other
revenues
|
(1 | ) | (1 | ) |
-
|
2
|
-
|
||||||||||||
Other
operations and
maintenance
|
(223 | ) | (130 | ) | (92 | ) |
19
|
(426 | ) | ||||||||||
Depreciation
and
amortization
|
(84 | ) | (53 | ) | (27 | ) | (5 | ) | (169 | ) | |||||||||
Taxes
other than income
taxes
|
(60 | ) | (30 | ) | (6 | ) |
-
|
(96 | ) | ||||||||||
Other
income and
(expenses)
|
9
|
6
|
1
|
-
|
16
|
||||||||||||||
Interest
expense
|
(51 | ) | (32 | ) | (28 | ) |
3
|
(108 | ) | ||||||||||
Income
taxes
|
(30 | ) | (11 | ) | (37 | ) |
-
|
(78 | ) | ||||||||||
Minority
interest and preferred dividends
|
(2 | ) | (1 | ) | (6 | ) |
-
|
(9 | ) | ||||||||||
Net
income
|
$ |
66
|
$ |
19
|
$ |
56
|
$ |
2
|
$ |
143
|
|||||||||
Three
Months 2006:
|
|||||||||||||||||||
Electric
margin
|
$ |
496
|
$ |
209
|
$ |
165
|
$ | (16 | ) |
854
|
|||||||||
Gas
margin
|
10
|
60
|
-
|
(2 | ) |
68
|
|||||||||||||
Other
revenues
|
-
|
(1 | ) |
-
|
1
|
-
|
|||||||||||||
Other
operations and
maintenance
|
(196 | ) | (124 | ) | (82 | ) |
8
|
(394 | ) | ||||||||||
Depreciation
and
amortization
|
(81 | ) | (48 | ) | (27 | ) | (6 | ) | (162 | ) | |||||||||
Taxes
other than income
taxes
|
(59 | ) | (27 | ) | (6 | ) |
2
|
(90 | ) | ||||||||||
Other
income and
(expenses)
|
7
|
4
|
1
|
(2 | ) |
10
|
|||||||||||||
Interest
expense
|
(44 | ) | (22 | ) | (26 | ) |
5
|
(87 | ) | ||||||||||
Income
taxes
|
(52 | ) | (17 | ) | (7 | ) |
8
|
(68 | ) | ||||||||||
Minority
interest and preferred dividends
|
(3 | ) | (1 | ) | (5 | ) |
1
|
(8 | ) | ||||||||||
Net
income
|
$ |
78
|
$ |
33
|
$ |
13
|
$ | (1 | ) | $ |
123
|
||||||||
Six
Months 2007:
|
|||||||||||||||||||
Electric
margin
|
$ |
909
|
$ |
379
|
$ |
501
|
$ | (30 | ) | $ |
1,759
|
||||||||
Gas
margin
|
41
|
179
|
-
|
(4 | ) |
216
|
|||||||||||||
Other
revenues
|
-
|
1
|
-
|
(1 | ) |
-
|
|||||||||||||
Other
operations and
maintenance
|
(446 | ) | (256 | ) | (160 | ) |
40
|
(822 | ) | ||||||||||
Depreciation
and
amortization
|
(171 | ) | (108 | ) | (54 | ) | (12 | ) | (345 | ) | |||||||||
Taxes
other than income
taxes
|
(117 | ) | (66 | ) | (14 | ) | (1 | ) | (198 | ) | |||||||||
Other
income and
(expenses)
|
16
|
10
|
2
|
2
|
30
|
||||||||||||||
Interest
expense
|
(97 | ) | (61 | ) | (53 | ) |
5
|
(206 | ) | ||||||||||
Income
taxes
|
(43 | ) | (27 | ) | (83 | ) |
4
|
(149 | ) | ||||||||||
Minority
interest and preferred dividends
|
(3 | ) | (3 | ) | (13 | ) |
-
|
(19 | ) | ||||||||||
Net
income
|
$ |
89
|
$ |
48
|
$ |
126
|
$ |
3
|
$ |
266
|
|||||||||
Six
Months 2006:
|
|||||||||||||||||||
Electric
margin
|
$ |
870
|
$ |
349
|
$ |
349
|
$ | (28 | ) |
1,540
|
|||||||||
Gas
margin
|
35
|
170
|
-
|
(1 | ) |
204
|
|||||||||||||
Other
revenues
|
1
|
(1 | ) |
-
|
-
|
-
|
|||||||||||||
Other
operations and
maintenance
|
(367 | ) | (248 | ) | (151 | ) |
20
|
(746 | ) | ||||||||||
Depreciation
and
amortization
|
(161 | ) | (95 | ) | (53 | ) | (14 | ) | (323 | ) | |||||||||
Taxes
other than income
taxes
|
(118 | ) | (70 | ) | (14 | ) | (1 | ) | (203 | ) | |||||||||
Other
income and
(expenses)
|
9
|
6
|
1
|
(1 | ) |
15
|
|||||||||||||
Interest
expense
|
(80 | ) | (45 | ) | (51 | ) |
12
|
(164 | ) | ||||||||||
Income
taxes
|
(72 | ) | (21 | ) | (29 | ) |
10
|
(112 | ) | ||||||||||
Minority
interest and preferred dividends
|
(4 | ) | (3 | ) | (12 | ) |
1
|
(18 | ) | ||||||||||
Net
income
|
$ |
113
|
$ |
42
|
$ |
40
|
$ | (2 | ) | $ |
193
|
60
Margins
The
following table presents the favorable (unfavorable) variations in the
registrants’ electric and gas margins for the three months and six months ended
June 30, 2007, compared with the same periods in 2006. Electric margins
are
defined as electric revenues less fuel and purchased power costs. Gas
margins
are defined as gas revenues less gas purchased for resale. We consider
electric,
interchange and gas margins useful measures to analyze the change in
profitability of our electric and gas operations between periods. We
have
included the analysis below as a complement to the financial information
we
provide in accordance with GAAP. However, these margins may not be a
presentation defined under GAAP and may not be comparable to other companies’
presentations or more useful than the GAAP information we provide elsewhere
in
this report.
Three
Months
|
Ameren(a)
|
UE
|
CIPS
|
Genco
|
CILCORP
|
CILCO
|
IP
|
||||||||||||||||||||
Electric
revenue change:
|
|||||||||||||||||||||||||||
Effect
of weather (estimate)
|
$ |
28
|
$ |
14
|
$ |
6
|
$ |
-
|
$ |
2
|
$ |
2
|
$ |
6
|
|||||||||||||
Interchange
revenues- affiliated(b)
|
-
|
(49 | ) |
-
|
(28 | ) |
-
|
-
|
-
|
||||||||||||||||||
Interchange
revenues- other
|
31
|
31
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||||
Other
(estimate)
|
77
|
(15 | ) |
6
|
(25 | ) |
62
|
62
|
3
|
||||||||||||||||||
Total
|
$ |
136
|
$ | (19 | ) | $ |
12
|
$ | (53 | ) | $ |
64
|
$ |
64
|
$ |
9
|
|||||||||||
Fuel
and purchased power change:
|
|||||||||||||||||||||||||||
Fuel:
|
|||||||||||||||||||||||||||
Generation
and
other
|
$ |
2
|
$ |
3
|
$ |
-
|
$ | (14 | ) | $ |
11
|
$ |
12
|
$ |
-
|
||||||||||||
Emission
allowance
costs
|
6
|
2
|
-
|
1
|
5
|
2
|
-
|
||||||||||||||||||||
Price
|
(24 | ) | (24 | ) |
-
|
-
|
(1 | ) | (1 | ) |
-
|
||||||||||||||||
Purchased
power
|
(37 | ) |
39
|
(14 | ) |
90
|
(55 | ) | (55 | ) | (7 | ) | |||||||||||||||
Total
fuel and purchased power change
|
$ | (53 | ) | $ |
20
|
$ | (14 | ) | $ |
77
|
$ | (40 | ) | $ | (42 | ) | $ | (7 | ) | ||||||||
Net
change in electric margins
|
$ |
83
|
$ |
1
|
$ | (2 | ) | $ |
24
|
$ |
24
|
$ |
22
|
$ |
2
|
||||||||||||
Net
change in gas margins
|
$ |
8
|
$ |
4
|
$ |
1
|
$ |
-
|
$ |
2
|
$ |
2
|
$ | (2 | ) | ||||||||||||
Six
Months
|
|||||||||||||||||||||||||||
Electric
revenue change:
|
|||||||||||||||||||||||||||
Effect
of weather (estimate)
|
$ |
46
|
$ |
21
|
$ |
11
|
$ |
-
|
$ |
6
|
$ |
6
|
$ |
8
|
|||||||||||||
Interchange
revenues- affiliated(b)
|
-
|
(121 | ) |
-
|
(46 | ) |
-
|
-
|
-
|
||||||||||||||||||
Interchange
revenues- other
|
92
|
92
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||||
Other
(estimate)
|
245
|
(5 | ) |
52
|
(11 | ) |
141
|
141
|
31
|
||||||||||||||||||
Total
|
$ |
383
|
$ | (13 | ) | $ |
63
|
$ | (57 | ) | $ |
147
|
$ |
147
|
$ |
39
|
|||||||||||
Fuel
and purchased power change:
|
|||||||||||||||||||||||||||
Fuel:
|
|||||||||||||||||||||||||||
Generation
and
other
|
$ | (7 | ) | $ |
11
|
$ |
-
|
$ | (29 | ) | $ |
13
|
$ |
14
|
$ |
-
|
|||||||||||
Emission
allowance
costs
|
22
|
5
|
-
|
6
|
9
|
6
|
-
|
||||||||||||||||||||
Price
|
(42 | ) | (35 | ) |
-
|
(2 | ) | (6 | ) | (6 | ) |
-
|
|||||||||||||||
Purchased
power
|
(137 | ) |
73
|
(47 | ) |
165
|
(125 | ) | (125 | ) | (19 | ) | |||||||||||||||
Total
fuel and purchased power change
|
$ | (164 | ) | $ |
54
|
$ | (47 | ) | $ |
140
|
$ | (109 | ) | $ | (111 | ) | $ | (19 | ) | ||||||||
Net
change in electric margins
|
$ |
219
|
$ |
41
|
$ |
16
|
$ |
83
|
$ |
38
|
$ |
36
|
$ |
20
|
|||||||||||||
Net
change in gas margins
|
$ |
12
|
$ |
6
|
$ |
3
|
$ |
-
|
$ |
3
|
$ |
3
|
$ |
-
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries
and
intercompany eliminations.
|
(b)
|
Includes
revenues from sales transferred between UE and Genco under
the former JDA,
which terminated on December 31,
2006.
|
Ameren
Ameren’s
electric margin increased by $83 million and $219 million, for the three
months
and six months ended June 30, 2007, compared with the same periods in
2006. The
following items had a favorable impact on electric margins for the second
quarter and first six months of 2007 as compared to the year-ago
periods:
·
|
Non-rate-regulated
Generation selling more power at market-based prices in the
second quarter
and first six months of 2007 compared with sales under below
market-based
power supply agreements, which expired on December 31,
2006;
|
·
|
Illinois
electric delivery service rate increases which commenced January
2,
2007;
|
·
|
emission
allowance costs were $6 million and $22 million lower, for
the three
months and six months ended June 30, 2007,
respectively;
|
·
|
favorable
weather conditions increased electric margins by $13 million
and $22
million for the three months and six months ended June 30,
2007;
|
·
|
MISO
costs were $8 million lower for the quarter compared with the
same period
in 2006;
|
·
|
return
to normal rainfall levels, which increased hydroelectric
generation;
|
·
|
the
lack of $6 million in fees 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 and the subsequent May 2007 MoPSC
rate order
that directed AmerenUE to transfer $4 million of the total
fees to an
asset account, which will be amortized over 25
years;
|
61
·
|
UE’s
electric rate increase that went into effect June 4, 2007;
and
|
·
|
storm-related
outages in the second quarter of 2006 that decreased interchange
margin by
$3 million.
|
The
following items had an unfavorable impact on electric margins for the
second
quarter and first six months of 2007 as compared to the year-ago
periods:
·
|
an
11% increase in coal and related transportation prices for
both the second
quarter and the first six months of
2007;
|
·
|
MISO
costs were $13 million higher for the six months ended June
30, 2007,
compared with the same period in 2006. Costs related to participation
in
the MISO Day Two Energy Market were higher for the year because
of a March
2007 FERC order that reallocated costs related to participation
in the
MISO Day Two Energy Market among market participants retroactive
to
2005;
|
·
|
elimination
of bundled power and delivery service tariffs in Illinois Regulated
operations; and
|
·
|
reduced
power plant availability, primarily at UE’s and AERG’s
plants.
|
Ameren’s
gas margin increased by $8 million, or 12%, and $12 million, or 6%, for
the
three months and six months ended June 30, 2007, respectively, compared
with the
same periods in 2006 primarily because of favorable weather conditions
as was
evidenced by a 38% and 16% increase in heating degree-days for the three
months
and six months ended June 30, 2007, respectively.
Missouri
Regulated
UE
UE’s
electric margin increased $1
million for the three months ended and $41 million for the six months
ended June
30, 2007, compared to the same periods in 2006. The increase in the six
month
period was primarily due to:
·
|
an
increase in margins on interchange sales primarily because
of the
termination of the JDA on December 31, 2006. This termination
of the JDA
provided UE with the ability to sell its excess power, originally
obligated under the JDA at cost, in the spot market at higher
market
prices;
|
·
|
the
lack of $6 million in fees 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 and the subsequent June 2007 MoPSC
rate order,
which directed UE to transfer $4 million of the total fees
to an asset
account, which will be amortized over 25
years;
|
·
|
return
to normal rainfall levels, which increased hydroelectric
generation;
|
·
|
increased
electric rates as approved by the MoPSC effective June 4,
2007;
|
·
|
favorable
weather conditions which increased electric margin by $10 million
and $13
million for the three months and six months ended June 30,
2007,
respectively;
|
·
|
MISO
costs, excluding the March 2007 FERC order, discussed below,
were $4
million lower for the second quarter and $17 million lower
for the six
months ended June 30, 2007, compared to the same periods in
2006;
and
|
·
|
spring
storm-related outages in the second quarter of 2006, which
reduced 2006
electric margins by $3 million.
|
Factors
that had an unfavorable impact on electric margin for the three months
and six
months ended June 30, 2007, as compared to the same periods in the prior
year
were as follows:
·
|
reduced
power plant availability because of planned maintenance
activities;
|
·
|
the
38-day planned refueling and maintenance outage at the Callaway
nuclear
plant in the second quarter of 2007, which was offset by the
unplanned
outage that occurred at the Callaway nuclear plant during the
second
quarter of 2006;
|
·
|
a
14% increase in coal and related transportation prices;
and
|
·
|
MISO
costs were $11 million higher for the six months ended June
30, 2007,
compared to the same period in 2006, due to the March 2007
FERC
order.
|
UE’s
gas margin increased by $4
million and $6 million for the three months and six months ended June
30, 2007,
respectively, compared with the same periods in 2006 primarily because
of
favorable weather conditions as evidenced by a 62% and 16% increase in
heating
degree-days for the three months and six months ended June 30, 2007,
respectively. The impact of the gas rate increase, as approved by the
MoPSC
effective April 1, 2007, was minimal in the second quarter.
Illinois
Regulated
Illinois
Regulated’s electric margin
declined by $2 million during the second quarter, but increased $30 million
for
the six months ended June 30, 2007, compared with the same periods in
2006.
Illinois Regulated’s gas margin increased by $4 million, or 7%, and $9 million,
or 5%, for the three months and six months ended June 30, 2007, respectively,
compared with the same periods in 2006.
62
CIPS
CIPS’
electric margin decreased by $2 million, or 3%, for the three months
ended June
30, 2007, but increased $16 million, or 14%, for the six months ended June
30, 2007, compared to the same periods in 2006. The increase in electric
margin
for the six-month period was primarily because of the combined effect
of the
elimination of bundled tariffs, including below-average seasonal rates,
the
expiration of below-market power supply contracts, and the January 1,
2007,
implementation of delivery service tariffs and the pass-through of purchased
power costs and favorable weather conditions that increased electric
margins for
the six months ended June 30, 2007 by $4 million.
CIPS’
electric
margin for the six
months ended June 30, 2007, was reduced by $4 million because of a March
2007
FERC order that reallocated costs among market participants retroactive
to
2005.
CIPS’
gas
margin increased by $1
million, or 7%, and $3 million, or 8%, for the three months and six months
ended June 30, 2007, respectively, compared with the same periods in
2006
primarily because of favorable weather conditions as evidenced by a 16%
increase
in year-to-date heating degree-days compared to the first six months
of
2006.
CILCO
(Illinois
Regulated)
The
following table provides a reconciliation of CILCO’s change in electric margin
by segment to CILCO’s total change in electric margin for the three months and
six months ended June 30, 2007, as compared with the same periods in
2006:
Three
Months
|
Six
Months
|
||||||
CILCO
(Illinois Regulated)
|
$ | (1 | ) | $ | (5 | ) | |
CILCO
(AERG)
|
23
|
41
|
|||||
Total
change in electric margin
|
$ |
22
|
$ |
36
|
CILCO’s
(Illinois Regulated) electric margin decreased by $1 million, or 3%,
and $5
million, or 7%, for the three months and six months ended June 30, 2007,
respectively, compared to the same periods in 2006. The margin decrease
was a
result of the combined effect of the elimination of bundled tariffs,
including
below-average seasonal rates, the expiration of below-market power supply
contracts, and the January 1, 2007, implementation of delivery service
tariffs
and the pass-through of purchased power costs.
Year-to-date
MISO costs increased $3 million because of the March 2007 FERC order
noted
above.
The
decrease in electric margin was
reduced by favorable weather conditions, which increased electric margin
by $2
million for the six months ended June 30, 2007.
See
Non-rate-regulated Generation
below for a detailed explanation of CILCO’s (AERG) change in electric margin for
the three months and six months ended June 30, 2007, as compared with
the same
periods in 2006.
CILCO’s
(Illinois Regulated) gas
margin increased by $2 million and $3 million for the three months and
six
months ended June 30, 2007, respectively, compared to the same periods
in 2006.
Favorable weather conditions as evidenced by a 10% and 15% increase in
heating
degree-days for the second quarter and six months ended June 30, 2007,
respectively, together with growth in the industrial sector were primarily
responsible for the favorable impact.
IP
IP’s
electric margin increased by $2
million, or 2%, and $20 million, or 12%, for the three months and six
months
ended June 30, 2007, respectively, compared with the same periods in
2006
primarily because of the combined effect of the elimination of bundled
tariffs,
including below-average winter rates, the expiration of below-market
power
supply contracts, and the January 1, 2007, implementation of delivery
service
tariffs and the pass-through of purchased power costs. Favorable weather
conditions also increased margin by $2 million for the six months ended
June 30, 2007.
The
March 2007 FERC order, referenced
above, reduced IP’s
electric margin by $12 million, in the first six months of 2007 as compared
to
the same period a year ago.
IP’s
gas
margin declined $2 million for the three months ended June 30, 2007,
and was
unchanged for the six months ended June 30, 2007, compared to the same
periods
in 2006, primarily because of favorable weather conditions as evidenced
by a 35%
and 15% increase in heating-degree days for the second quarter and six
months
ended June 30, 2007, respectively, partially offset by reduced transportation
and other gas margins.
Non-rate-regulated
Generation
Non-rate-regulated
Generation’s
electric margin increased by $86 million, or 52%, and $152 million, or
44%, for
the three months and six months ended June 30, 2007, respectively, compared
with
the same periods in 2006.
Genco
Genco’s
electric margin increased by $24 million, or 27%, and $83 million, or
49%, for
the three months and six months ended June 30, 2007, respectively, compared
with
the same periods in 2006, primarily because of:
·
|
selling
power at market-based prices in the second quarter of 2007
compared with
selling power at below-market prices pursuant to cost-based
power supply
agreements, which expired on December 31,
2006;
|
63
·
|
increased
power plant availability due to reduced planned outages this
year;
|
·
|
reduced
emission allowance costs; and
|
·
|
lower
MISO costs totaling $9 million for the six months ended June
30, 2007,
compared to the first half of 2006, as a result of the March
2007 FERC
order.
|
Genco’s
increase in electric margin
was reduced by:
·
|
the
loss of margins on sales supplied with power acquired through
the JDA;
and
|
·
|
a
2% increase in coal and related transportation prices for the
six months
ended June 30, 2007 compared to the first half of
2006.
|
CILCO
(AERG)
For
the three- and six-month periods
ended June 30, 2007, AERG’s electric margin increased by $23 million, or 84%,
and $41 million, or 65%, respectively, compared with the same periods
in 2006
primarily because of:
·
|
selling
power at market-based prices in the second quarter of 2007
compared with
sales under cost-based power supply agreements, which expired
on December
31, 2006; and
|
·
|
reduced
emission costs for both the second quarter and six months ended
June 30,
2007, compared to the same prior year
periods.
|
The
increase in electric margin was
reduced by:
·
|
a
16% increase in coal and related transportation prices for
the six months
ended June 30, 2007, compared to the first half of 2006;
and
|
·
|
reduced
plant availability because of planned extensive maintenance
activities,
which commenced in February 2007.
|
EEI
EEI’s
electric margins increased by
$10 million and $8 million for the three months and six months ended June
30, 2007, respectively, compared with the same periods in 2006 primarily
because
of higher market prices and increased sales partially offset by an increase
in
coal and related transportation prices.
Operating
Expenses and Other Statement of Income Items
Other
Operations and Maintenance
Ameren
Three
months - Other operations and
maintenance expenses increased $32 million in the second quarter of 2007
compared with the second quarter of 2006 primarily because of
$35
million of maintenance and labor costs associated with the Callaway nuclear
plant refueling and maintenance outage in the second quarter of 2007,
which
lasted 38 days. Refueling and maintenance outages occur approximately
every 18
months and typically include fuel replacement, maintenance, and inspections.
Additionally, higher non-Callaway labor costs, increased bad debt reserves
and
higher tree trimming expenditures resulted in increased other operations
and
maintenance expenses in the current year period. In the second quarter
of 2006,
Ameren recorded $10 million of costs related to the December 2005 reservoir
breach at UE’s Taum Sauk plant and $7 million of losses on the sale of noncore
properties. The absence of such items in the current year period resulted
in a
reduction of the increase in other operations and maintenance expenses
between
periods.
Six
months - Other operations and
maintenance expenses increased $76 million in the first six months of
2007
compared with the first six months of 2006 primarily because of expenditures
of
$29 million related to a severe ice storm in January 2007 in UE’s and CIPS’
service territories and $35 million of maintenance and labor costs
associated with the Callaway refueling and maintenance outage in the
second
quarter of 2007 as noted above. Higher non-Callaway labor costs and bad
debt
reserves also increased other operations and maintenance expenses in
the first
six months of 2007 compared to the prior-year period. Reducing the effect
of
these items was the absence of Taum Sauk costs and noncore property sale
losses
in the current year period, as noted above, and the reversal of an accrual
of
$15 million established in 2006 for contributions to assist customers
through
the Illinois Customer Elect electric rate increase phase-in plan.
Variations
in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s
business segments and for the Ameren Companies for the three months and
six
months ended June 30, 2007, compared with the same periods in 2006 were
as
follows:
Missouri
Regulated
UE
Three
months – Other operations and
maintenance expenses increased $26 million in the second quarter of 2007
compared with the second quarter of 2006 primarily because of
$35
million of maintenance and labor costs associated with the Callaway refueling
and maintenance outage in the second quarter of 2007, increased tree
trimming
expenditures, and insurance premiums paid to an affiliate for replacement
power
coverage. Reducing the effect of these items was the absence in the current
year
period of costs related to the December 2005 reservoir breach at UE’s Taum Sauk
plant.
64
Six
months - Other operations and
maintenance expenses increased $79 million in the first six months of
2007
compared with the first six months of 2006 primarily because of ice storm
repair
expenditures of $26 million, costs associated with the Callaway refueling
and
maintenance outage of $35 million, higher non-Callaway labor costs, and
insurance premiums for replacement power coverage of $9 million paid to an
affiliate. Reducing the effect of these items was the absence in the
current
year period of costs related to the Taum Sauk reservoir breach, as noted
above.
Illinois
Regulated
Other
operations and maintenance expenses increased $6 million and $8 million
in the
Illinois Regulated segment in the three months and six months ended June
30,
2007, respectively, compared with the same periods in 2006.
CIPS
Three
months – Other operations and maintenance expenses were comparable between
periods.
Six
months - Other operations and maintenance expenses increased $8 million
in the
first six months of 2007 compared with the first six months of 2006 primarily
because of storm repair expenditures of $3 million, higher labor costs
and
increased bad debt reserves as a result of the transition to higher electric
rates in Illinois. The reversal of the customer assistance program accrual
of $4
million established in 2006, as noted above, reduced the impact of these
increases.
CILCO
(Illinois Regulated)
Three
months – Other operations and maintenance expenses were comparable between
periods.
Six
months - Other operations and maintenance expenses decreased $3 million
in the
first six months of 2007 compared with the first six months of 2006 primarily
because of lower employee benefit costs and the reversal of the customer
assistance program accrual of $3 million established in 2006, as noted
above.
Reducing the benefit of these items was an increase in bad debt
reserves.
IP
Three
months – Other operations and maintenance expenses increased $2 million in the
second quarter of 2007 compared with the second quarter of 2006 primarily
because of higher bad debt reserves.
Six
months - Other operations and maintenance expenses were comparable between
periods. The reversal of the customer assistance program accrual of $8
million
established in 2006 as noted above, lower transmission and distribution
expenses, and decreased injuries and damages reserves were offset by
higher
employee benefit costs and increased bad debt reserves.
Non-rate-regulated
Generation
Other
operations and maintenance expenses increased $10 million and $9 million
in the
Non-rate-regulated Generation segment in the three months and six months
ended
June 30, 2007, respectively, compared with the same periods in
2006.
Genco
Three
months – Other operations and maintenance expenses were comparable between
periods.
Six
months - Other operations and maintenance expenses increased $4 million
in the
first six months of 2007 compared with the first six months of 2006 primarily
because of higher labor costs.
CILCORP
(Parent Company Only)
Three
months – Other operations and maintenance expenses increased $4 million in the
second quarter of 2007 compared with the second quarter of 2006 primarily
because of higher employee benefit costs.
Six
months - Other operations and maintenance expenses were comparable between
periods as the absence of a write-off in 2007 as occurred in the prior
year
period of an intangible asset established in conjunction with Ameren’s
acquisition of CILCORP was offset by increased employee benefit costs
in the
current year period.
CILCO
(AERG)
Three
and
six months - Other operations and maintenance expenses increased $2 million
and
$4 million, respectively, for the three months and six months ended June
30,
2007, as compared to the prior year periods primarily because of higher
plant
maintenance costs due to an extended scheduled plant outage.
EEI
Three
months and six months - Other operations and maintenance expenses were
comparable between periods.
Depreciation
and Amortization
Ameren
Three
and six months – Ameren’s
depreciation and amortization expenses increased $7 million and $22 million
in
65
the
three
months and six months ended June 30, 2007, respectively, compared with
the same
periods in 2006. The increases were primarily because of capital additions
in
2006 and the start of amortization of a regulatory asset in 2007 associated
with
acquisition integration costs at IP, as required by an ICC order.
Variations
in depreciation and
amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and
for the Ameren Companies for the three months and six months ended June
30,
2007, compared with the same periods in 2006 were as follows:
Missouri
Regulated
UE
Three
and six months – Depreciation
and amortization expenses increased $3 million and $10 million, respectively,
in
the three months and six months ended June 30, 2007, primarily because
of
capital additions in 2006, including CTs purchased in the second quarter
of
2006, and storm-related expenditures in 2006.
Illinois
Regulated
Depreciation
and amortization expenses increased $5 million and $13 million in the
Illinois Regulated segment in the three months and six months ended June
30,
2007, respectively, compared with the same periods in 2006.
CIPS
& CILCO (Illinois Regulated)
Three
and six months - Depreciation and
amortization expenses were comparable between periods.
IP
Three
and
six months – Depreciation and amortization expenses increased $5 million and $11
million, respectively, primarily because of amortization in 2007 of a
regulatory
asset associated with acquisition integration costs, as required by an
ICC
order.
Non-rate-regulated
Generation
Three
and
six months - Depreciation and amortization expenses were comparable in
the
Non-rate-regulated Generation segment and for Genco, CILCORP (Parent
Company
Only), CILCO (AERG) and EEI in the three months and six months ended
June 30,
2007, compared with the same periods in 2006.
Taxes
Other Than Income Taxes
Ameren
Three
months – Ameren’s taxes other
than income taxes increased $6 million in the second quarter of 2007
compared
with the second quarter of 2006 primarily because of higher payroll
taxes.
Six
months - Ameren’s taxes other
than income taxes decreased $5 million in the first six months of 2007
compared
with the first six months of 2006 primarily because of lower gross receipts
and
property taxes.
Variations
in taxes other than income
taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren
Companies for the three months and six months ended June 30, 2007, compared
with
the same periods in 2006 were as follows:
Missouri
Regulated
UE
Three
and six months – Taxes other than
income taxes were comparable between periods.
Illinois
Regulated
Taxes
other than income taxes in
Illinois Regulated were comparable in the second quarter of 2007 with
the second
quarter of 2006. Taxes other than income taxes decreased
$4
million in the six months ended June 30, 2007, compared with the same
period in
2006.
CIPS
Three
months – Taxes other than income
taxes were comparable between periods.
Six
months - Taxes other than income
taxes decreased $3 million in the first six months of 2007 compared with
the
first six months of 2006 primarily because of lower property taxes and
lower
gross receipts taxes.
CILCO
(Illinois Regulated) &
IP
Three
and six months – Taxes other than
income taxes were comparable between periods.
Non-rate-regulated
Generation
Three
and
six months - Taxes other than income taxes were comparable in the
Non-rate-regulated Generation segment and for Genco, CILCORP (Parent
Company
Only), CILCO (AERG) and EEI in the three months and six months
66
Other
Income and Expenses
Ameren
Three
and six months – Miscellaneous
income increased $9 million and $18 million in the three months and six
months
ended June 30, 2007, respectively, compared with the same periods in
2006,
primarily as a result of increased interest income. Miscellaneous income
in each
period includes interest income on industrial development revenue bonds
acquired
by UE in conjunction with its purchase of CTs. These amounts are offset
by an
equivalent amount of interest expense associated with capital leases
for the CTs
recorded in interest charges on Ameren’s and UE’s statements of income.
Miscellaneous expense increased $3 million in both the three- and six-month
periods ended June 30, 2007, compared with the same periods in 2006 as
discussed
below.
Variations
in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business
segments and for the Ameren Companies for the three months and six months
ended
June 30, 2007, compared with the same periods in 2006 were as
follows:
Missouri
Regulated
UE
Three
and
six months – Miscellaneous income increased $4 million and $8 million for the
three months and six months ended June 30, 2007, compared with the same
periods
in 2006, primarily as a result of increased interest income. As discussed
above,
miscellaneous income includes interest income related to industrial revenue
bonds that is offset in interest charges on UE’s statement of income.
Miscellaneous expense increased $4 million in both the three months and
six
months ended June 30, 2007, compared with the same periods in 2006, as
a result
of expenses related to UE’s electric rate case.
Illinois
Regulated
Miscellaneous
income increased $2 million and $3 million in the Illinois Regulated
segment in
the three months and six months ended June 30, 2007, respectively, compared
with
the same periods in 2006. Miscellaneous expense was comparable between
periods.
CIPS
& CILCO (Illinois Regulated)
Three
and six months - Other income and
expenses were comparable between periods.
IP
Three
and
six months – Miscellaneous income increased $3 million and $4 million for the
three months and six months ended June 30, 2007, compared with the same
periods
in 2006, primarily as a result of increased interest income. Miscellaneous
expense was comparable between periods.
Non-rate-regulated
Generation
Other
income and expenses were comparable in the Non-rate-regulated Generation
segment
and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in
the three
months and six months ended June 30, 2007, compared with the same periods
in
2006.
Interest
Ameren
Three
and
six months - Interest expense increased $21 million and $42 million in the
three months and six months ended June 30, 2007, respectively, compared
with the
same periods in 2006, primarily because of increased short-term borrowings
and
higher interest rates due to reduced credit ratings and other items noted
below.
Interest expense recognized on UE’s capital leases associated with the purchase
of CTs is offset by an equivalent amount of interest income recorded
in other
income and expenses on Ameren’s and UE’s statement of income. With the adoption
of FIN 48, we also began to record interest amounts associated with uncertain
tax positions as interest expense rather than income tax expense. These
interest
charges were $5 million and $7 million for the three months and six months
ended
June 30, 2007, respectively.
Variations
in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for
the Ameren Companies for the three months and six months ended June 30,
2007,
compared with the same periods in 2006, were as follows:
Missouri
Regulated
UE
Three
and
six months – Interest expense increased $7 million and $17 million for the
three months and six months ended June 30, 2007, compared with the same
periods
in 2006 primarily because of increased short-term borrowings and higher
interest
rates due to reduced credit ratings. As discussed above, interest charges
include interest expense related to capital leases that is offset in
other
income and expenses on UE’s statement of income. Interest expense recorded in
conjunction with the adoption of FIN 48 was
67
Illinois
Regulated
Interest
expense increased $10 million and $16 million in the Illinois Regulated
segment
in the three months and six months ended June 30, 2007, respectively,
compared
with the same periods in 2006.
CIPS
Three
and
six months – Interest expense increased $2 million and $3 million for the
three months and six months ended June 30, 2007, compared with the same
periods
in 2006, primarily because of increased short-term borrowings and higher
interest rates due to reduced credit ratings.
CILCO
(Illinois Regulated)
Three
and
six months - Interest expense was comparable between periods.
IP
Three
and
six months – Interest expense increased $8 million and $12 million for the
three months and six months ended June 30, 2007, compared with the same
periods
in 2006, primarily because of the issuance of $75 million senior secured
notes
in 2006 and increased short-term borrowings and higher interest rates
due to
reduced credit ratings.
Non-rate-regulated
Generation
Interest
expense was comparable at Non-rate-regulated Generation and at Genco,
CILCORP
(Parent Company Only), CILCO (AERG) and EEI in the three months and six
months
ended June 30, 2007, compared with the same periods in 2006.
Income
Taxes
Ameren
Three
and six months - Ameren’s
effective tax rate decreased in the three months and six months ended
June 30,
2007, as compared with the same periods in the prior year. Variations
in
effective tax rates in Ameren’s, CILCORP’s and CILCO’s business segments and for
the Ameren Companies for the three months and six months ended June 30,
2007,
compared with the same periods in 2006 were as follows:
Missouri
Regulated
UE
Three
and six months – The effective
tax rate decreased in the three months and six months ended June 30,
2007, as
compared with the same periods in the prior year, primarily because of
implementation of changes ordered by the MoPSC. Also, the effective tax
rate for
the three- and six-month periods in 2006 was increased by the effect
of higher
non-deductible
expenses than the same periods in 2007.
Illinois
Regulated
The
effective tax rate increased in the Illinois Regulated segment in the
three
months and six months ended June 30, 2007, respectively, compared with
the same
periods in 2006, due to items detailed below:
CIPS
Three
and six months – The effective
tax rate increased in the three months and six months ended June 30,
2007, as
compared with the same periods in the prior year, primarily because of
a
decrease in reserves for uncertain tax positions in 2006 for tax returns
filed
in prior years when compared to the same periods in 2007.
CILCO
(Illinois
Regulated)
Three
and six months – The effective
tax rate decreased in the three months and six months ended June 30,
2007, as
compared with the same periods in the prior year, primarily because of
an
increase in expenses deductible for tax which were not expensed for book
purposes.
IP
Three
months – The effective tax rate
decreased in the second quarter of 2007 compared with the second quarter
of 2006
primarily because of an increase in expenses deductible for tax which
were not
expensed for book purposes.
Six
months – The effective tax rate
was comparable between periods.
Non-rate-regulated
Generation
The
effective tax rate increased in the Non-rate-regulated Generation segment
in the
three month and six month periods ended June 30, 2007, compared with
the same
periods in 2006, due to the items detailed below:
68
Genco
Three
months – The effective tax rate
decreased in the second quarter of 2007 compared with the second quarter
of 2006
primarily because of an increase in reserves for uncertain tax positions
in 2006
for tax returns filed in prior years.
Six
months – The effective tax rate
decreased in the first six months of 2007 compared with the first six
months of
2006 primarily because of an increase in reserves for uncertain tax positions
in
2006 for tax returns filed in prior years, along with an increase in
expenses in
2007 that were deductible for tax purposes, but were not expensed for
book
purposes.
CILCO
(AERG)
Three
and six months – The effective
tax rate increased in the three months and six months ended June 30,
2007, as
compared with the same periods in the prior year, primarily because of
a
decrease in reserves for uncertain tax positions in 2006 for tax returns
filed
in prior years.
CILCORP
(Parent Company
Only)
Three
and six months – The effective
tax rate increased in the three months and six months ended June 30,
2007, as
compared with the same periods in the prior year, primarily because of
a
decrease in expenses deductible for tax that were not deductible for
book
purposes.
EEI
Three
and six months – The effective
tax rate decreased in the three months and six months ended June 30,
2007, as
compared with the same periods in the prior year, primarily because of
an
increase in expenses deductible for tax purposes which were not expensed
for
book purposes.
LIQUIDITY
AND CAPITAL RESOURCES
The
tariff-based gross margins of
Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO and IP)
continue to be the principal source of cash from operating activities
for Ameren
and its rate-regulated subsidiaries. A diversified retail customer mix
of
primarily rate-regulated residential, commercial and industrial classes
and a
commodity mix of gas and electric service provide a reasonably predictable
source of cash flows for Ameren, UE, CIPS, CILCO and IP. For operating
cash
flows, Genco and AERG principally rely on power sales to Marketing Company,
which sold power through the Illinois power procurement auction and is
selling
power through other primarily market-based contracts with wholesale and
retail
customers. The amount of power that Genco, AERG, EEI, Marketing Company
and
their affiliates could supply to CIPS, CILCO and IP through the Illinois
power
procurement auction was limited to 35% of CIPS’, CILCO’s and IP’s aggregate
annual load. In addition to cash flows from operating activities, the
Ameren
Companies use available cash, money pool or other short-term borrowings
from
affiliates, commercial paper, or credit facilities to support normal
operations
and other temporary capital requirements. The use of operating cash flows
and
short-term borrowings to fund capital expenditures and other investments
may
periodically result in a working capital deficit, as was the case at
June 30,
2007, for Ameren, UE, Genco, CILCORP, CILCO, and IP. The Ameren Companies
will
reduce their short-term borrowings with cash from operations or discretionarily
with long-term borrowings and in the case of Ameren subsidiaries, equity
infusions from Ameren. See Note 2 – Rate and Regulatory Matters to our financial
statements under Part I, Item 1 of this report for a discussion of a
comprehensive rate relief and customer assistance program in Illinois
that among
other things, would change the process for power procurement in Illinois
in the
future and would impact future cash flows of the Ameren Companies, except
UE,
subject to enactment of enabling legislation.
The
following table presents net
cash provided
by (used in)
operating, investing and financing activities for the six months ended
June 30,
2007 and 2006:
Net
Cash Provided By
Operating
Activities
|
Net
Cash Used In
Investing
Activities
|
Net
Cash Provided By
(Used
In) Financing Activities
|
|||||||||||||||||||||||||||||||||
2007
|
2006
|
Variance
|
2007
|
2006
|
Variance
|
2007
|
2006
|
Variance
|
|||||||||||||||||||||||||||
Ameren(a)
|
$ |
543
|
$ |
619
|
$ | (76 | ) | $ | (754 | ) | $ | (795 | ) | $ |
41
|
$ |
761
|
$ |
131
|
$ |
630
|
||||||||||||||
UE
|
145
|
258
|
(113 | ) | (381 | ) | (475 | ) |
94
|
444
|
198
|
246
|
|||||||||||||||||||||||
CIPS
|
44
|
80
|
(36 | ) | (1 | ) | (24 | ) |
23
|
99
|
(55 | ) |
154
|
||||||||||||||||||||||
Genco
|
115
|
63
|
52
|
(81 | ) | (64 | ) | (17 | ) | (34 | ) |
2
|
(36 | ) | |||||||||||||||||||||
CILCORP
|
62
|
112
|
(50 | ) | (85 | ) | (6 | ) | (79 | ) |
127
|
(86 | ) |
213
|
|||||||||||||||||||||
CILCO
|
89
|
119
|
(30 | ) | (85 | ) | (48 | ) | (37 | ) |
88
|
(51 | ) |
139
|
|||||||||||||||||||||
IP
|
73
|
85
|
(12 | ) | (93 | ) | (82 | ) | (11 | ) |
163
|
(2 | ) |
165
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries
and
intercompany eliminations.
|
69
Cash
Flows from Operating Activities
Ameren’s
cash from operations
decreased in the first six months of 2007, as compared with the first
six months
of 2006. Working capital investment increased as a result of the collection
of
higher electric rates from customers lagging payments for power purchases.
In
addition, other operations and maintenance expenses increased, as discussed
in
Results of Operations, primarily as a result of the Callaway nuclear
plant
refueling and maintenance outage and storm-related outage repairs. Positive
impacts on cash flow from operations included increases in electric and
gas
margins, and a decrease in income taxes paid (net of refunds) of $90
million.
At
UE, cash from operating activities
decreased in the first six months of 2007, as compared with the first
six months
of 2006. Storm repair costs and increased other operations and maintenance
expenses as a result of the Callaway nuclear plant refueling and maintenance
outage were only partially offset by increased electric and gas margins,
as
discussed in Results of Operations. In addition, there was an increase
in
accounts receivable, primarily because of higher prices for interchange
sales.
Compared to the prior-year period, decreases in cash paid for Taum Sauk
costs
(net of insurance recoveries) of $33 million, and a decrease in income
tax
payments (net of refunds) of $69 million benefited cash flow from
operations.
At
CIPS, cash from operating
activities decreased in the first six months of 2007, as compared with
the first
six months of 2006. Electric and gas margins were higher, but other operations
and maintenance expenses also increased, as discussed in Results of Operations.
An increased investment in working capital, as a result of the collection
of
higher electric rates from customers lagging payments for power purchases
and an
increase in past due customer accounts were the primary reasons for the
overall
decrease in operating cash flows. Income tax payments (net of refunds)
decreased
$23 million, benefiting cash flows from operations.
Genco’s
cash from operating
activities increased in the first six months of 2007 compared to the
2006
period, primarily because of an increase in electric margins, as
discussed
in Results of Operations, and a reduction in cash spent for fuel inventory,
due
to large cash outlays made in 2006 to replenish coal inventory after
disruptions
in rail deliveries caused by train derailments. Reducing these increases
in cash
from operating activities was an increase in income tax payments (net
of
refunds) of $12 million.
Cash
from operating activities
decreased for CILCORP and CILCO in the six months ended June 30, 2007,
compared
with the same period of 2006. The positive cash effect of the increased
electric
margins discussed in Results of Operations was reduced by an increased
investment in working capital, as a result of the collection of higher
electric
rates from customers lagging payments for power purchases and an increase
in
past due customer accounts. Income tax payments (net of refunds) were
comparable
year over year for CILCORP and decreased $5 million for CILCO.
IP’s
cash from operations decreased
in the six months ended June 30, 2007, compared with the 2006 period,
despite
higher electric margins as discussed in Results of Operations. An increased
investment in working capital, as a result of the collection of higher
electric
rates from customers lagging payments for power purchases and an increase
in
past due customer accounts were the primary reasons for the overall decrease
in
operating cash flows. Income tax payments (net of refunds) decreased
by $4
million.
Cash
Flows from Investing Activities
Ameren
had a decrease in cash
used in investing activities in the first six months of 2007 compared to
the first six months of 2006. Net cash used for capital expenditures
and CT
acquisitions decreased in 2007 as increased storm repair costs and scrubber
projects and upgrades at various power plants were more than offset by
the lack
of CT acquisitions in 2007 as occurred in 2006. In addition, a $29 million
decrease in emission allowance purchases reduced cash flows from investing
activities.
UE’s
cash used in investing activities
decreased in the first six months of 2007, compared to the same period
in 2006,
principally because of the $292 million expended for CT purchases in
2006,
partially offset by a $133 million increase in capital expenditures in
the first
six months of 2007 as compared with the first six months of 2006. The
increased
capital expenditures in 2007 were related to storm costs, a scrubber
project,
and other power plant upgrades. In the 2006 period, UE received proceeds
of $67
million from an intercompany note. The absence of these proceeds in the
2007
period further reduced cash from investing activities compared to the
same
period in 2006.
CIPS
had a reduction in its net use of
cash from investing activities during 2007 as compared to the same period
in
2006. The net $23 million reduction was primarily due to changes in money
pool
advances. In the 2007 period, CIPS received net money pool repayments
of $1
million but in 2006 had net advances to the money pool of $17
million.
Genco’s
cash used in investing
activities increased in the first six months of 2007 compared with the
2006
period. Capital expenditures increased $38 million, principally due to
a
scrubber project at one of its plants, while emission allowance purchases
decreased by $21 million.
CILCORP’s
and CILCO’s cash used in
investing activities increased in the six months ended June 30,
2007,
70
compared
with the same period in 2006. Cash flow used in investing activities
increased
as a result of a $79 million increase in capital expenditures, primarily
due to
a scrubber project and plant upgrades at CILCO subsidiary AERG, the absence
in
2007 of $11 million of proceeds in 2006 from the sale of leveraged leases,
and (for CILCORP only) the absence in 2007 of a 2006 note receivable
payment
from Resources Company in the amount of $42 million. The receipt of a
$42
million repayment of prior year money pool advances and a $12 million
reduction
of emission allowance purchases increased cash used in investing
activities.
IP’s
cash used in investing activities
increased in the first six months of 2007 compared to the same period
in 2006 as
a result of increased capital expenditures.
See
Note 8 – Commitments and
Contingencies to our financial statements under Part I, Item 1, of this
report
for a discussion of future environmental capital expenditure
estimates.
We
continually review our power
supply needs. As a result, we could modify plans for generation capacity,
which
could include changing the times when certain assets will be added to
or removed
from our portfolio, the type of generation asset technology that will
be
employed, and whether capacity may be purchased, among other things.
Any changes
that we may plan to make for future generating needs could result in
significant
capital expenditures or losses being incurred, which could be
material.
Cash
Flows from Financing Activities
Cash
provided by financing activities
increased for Ameren in the first six months of 2007 from the year-ago
period.
Cash from financing activities increased as a result of a
$425
million debt issuance in June 2007 by UE, which was larger than the prior
year’s
issuances totaling $232 million. The proceeds of the $425 million offering
were
used to reduce short-tem debt at UE. Short-term debt increased $803 million
year
over year. The increase in short-term debt was used to pay maturing long-term
notes and to fund working capital requirements at Ameren’s subsidiaries. Cash
was reduced by a $9 million decrease in common stock issuances, and a
$357
million increase in long-term debt redemptions, repurchases and maturities,
including the maturity of $350 million in notes at Ameren Corporation
in the
first six months of 2007.
UE’s
cash from financing activities
increased for the first six months of 2007, compared to the same period
last
year, primarily due to the issuance of $425 million in long-term debt
in June
2007. The proceeds were used to reduce short-tem debt. Overall, short-term
debt
decreased $92 million in 2007 compared to the same period in 2006. Short-term
borrowings were used in 2007 to fund working capital requirements, and
in 2006
principally to fund the acquisition of CTs. In 2007 compared to 2006,
cash from
financing activities was decreased by a
$43
million increase in dividend payments and $40 million in net repayments
on an
intercompany borrowing arrangement with Ameren.
CIPS
had a net source of cash from
financing activities for the six months ended June 30, 2007, compared
to a net
use of cash for the first six months of 2006. Cash from financing activities
increased as a result of a $100 million increase in short-tem debt, a
$25
million decrease in dividends paid, a $20 million reduction in long-term
debt
maturities, and the absence in 2007 of a 2006 intercompany note payment
to UE in
the amount of $67 million. Reducing these positive effects was the absence
in
2007 of $61 million in proceeds from long-term debt issuances in
2006.
Genco
had a net use of cash from
financing activities for the six months ended June 30, 2007, compared
to a net
source of cash for the first six months of 2006. The increase in cash
used in
financing activities in 2007 was a result of a $42 million increase in
dividend payments and the absence in 2007 of a $50 million capital contribution
that was received in 2006. Reducing the net cash used in financing activities
was an increase in net money pool borrowings of $59 million in the first
six
months of 2007 compared to the same period in 2006.
CILCORP
and CILCO had a net source of
cash from financing activities for the six months ended June 30, 2007,
compared
to a net use of cash for the first six months of 2006. Short-term debt
increased
year over year by $250 million for CILCORP and $125 million for CILCO.
Dividends
were not paid by either company in 2007, compared to $50 million paid
in 2006.
Also benefiting cash in 2007 compared to 2006 was the absence of money
pool
repayments in 2007, compared to 2006 repayments of $89 million at CILCORP
and
$95 million at CILCO. Cash flows from financing activities were reduced
by a $43
million increase in CILCORP note repayments, a $96
million reduction in long-term debt proceeds at both CILCORP and CILCO,
and
increased redemptions, repurchases, and maturities of long-term debt
of $38
million and $50 million at CILCORP and CILCO, respectively.
IP
had a net source of cash from
financing activities in the first six months of 2007, compared to a net
use of
cash in the same period of the prior year. Cash was benefited
by
$250
million of short-term debt in 2007 compared to none in 2006, and by an
$8
million decrease in TFN overfunding, but was reduced by the lack of long-term
debt proceeds in 2007, compared to $75 million in 2006, and by a $22
million
increase in net repayments of money pool borrowings.
71
Short-term
Borrowings and Liquidity
Short-term
borrowings typically consist
of drawings under committed bank credit facilities and commercial paper
issuances. For additional information on credit facilities, short-term
borrowing
activity, relevant interest rates, and borrowings under Ameren’s utility and
non-state-regulated subsidiary money pool arrangements, see Note 3 – Credit
Facilities and Liquidity to our financial statements under Part I, Item
1, of
this report.
The
following table presents the
various committed bank credit facilities of the Ameren Companies and
AERG and
their availability as of June 30, 2007:
Credit
Facility
|
Expiration
|
Amount
Committed
|
Amount
Available
|
|||||
Ameren,
UE and Genco:
|
||||||||
Multiyear
revolving(a)
|
July
2010
|
$ |
1,150
|
$ |
369
|
|||
CIPS,
CILCORP, CILCO, IP and AERG:
|
||||||||
2007
Multiyear revolving(b)
|
January
2010
|
500
|
75
|
|||||
2006
Multiyear revolving(c)
|
January
2010
|
500
|
-
|
(a)
|
Ameren
Companies may access this credit facility through intercompany
borrowing
arrangements. The maximum amount available to Ameren, UE and
Genco is
$1.15 billion,
$500
million and $150 million,
respectively.
|
(b)
|
The
maximum amount available to each borrower at June 30, 2007,
including for
the issuance of letters of credit, was limited as follows:
CILCORP
- $125 million, IP - $200 million and AERG - $100 million. CIPS
and
CILCO have the option of permanently reducing their ability
to borrow
under the 2006 $500 million credit facility and shifting such
capacity, up
to the same limits, to the 2007 $500 million credit facility.
In July
2007, CILCO shifted $75 million of its sublimit under the 2006
$500
million credit facility to this
facility.
|
(c)
|
The
maximum amount available to each borrower at June 30, 2007,
including for
issuance of letters of credit, was limited as follows: CIPS
- $135
million, CILCORP - $50 million, CILCO - $150 million, IP -
$150 million
and AERG - $200 million. In July 2007, CILCO shifted $75 million
of its
capacity under this facility to the 2007 $500 million credit
facility.
Accordingly, as of July 31, 2007, CILCO had a sublimit of $75
million
under this facility and a $75 million sublimit under the 2007
credit
facility.
|
In
addition to committed credit facilities, a further source of liquidity
for the
Ameren Companies from time to time is available cash and cash
equivalents.
The
issuance of short-term debt securities by Ameren’s utility subsidiaries is
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. The authorization was effective as of April 1, 2006, and
terminates on March 31, 2008. IP has unlimited short-term debt authorization
from FERC.
Genco
is
authorized by FERC in its March 2006 order to have up to $300 million
of
short-term debt outstanding at any time. AERG and EEI have unlimited
short-term
debt authorization from FERC.
With
the
repeal of PUHCA 1935, the issuance of short-term unsecured 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.
The
Ameren Companies continually
evaluate the adequacy and appropriateness of their credit arrangements
given
changing business conditions. When business conditions warrant, changes
may be
made to existing credit agreements or other short-term borrowing
arrangements.
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 (net of any issuance discounts and including
any
redemption premiums) for the six months ended June 30, 2007 and 2006,
for the
Ameren Companies. For additional information related to the terms and
uses of
these issuances and the sources of funds and terms for the redemptions,
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
|
2007
|
2006
|
||||||
Issuances
|
||||||||
Long-term
debt
|
||||||||
UE:
|
||||||||
6.40%
Senior secured notes due
2017
|
June
|
$ |
425
|
$ |
-
|
|||
CIPS:
|
||||||||
6.70%
Senior secured notes due
2036
|
June
|
-
|
61
|
72
Six
Months
|
||||||||
Month
Issued, Redeemed,
Repurchased
or Matured
|
2007
|
2006
|
||||||
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
|
$ |
425
|
$ |
232
|
||||
Common
stock
|
||||||||
Ameren:
|
||||||||
DRPlus
and
401(k)
|
Various
|
$ |
48
|
$ |
57
|
|||
Total
common stock issuances
|
$ |
48
|
$ |
57
|
||||
Total
Ameren long-term debt and common stock issuances
|
$ |
473
|
$ |
289
|
||||
Redemptions,
Repurchases and Maturities
|
||||||||
Long-term
debt
|
||||||||
Ameren:
|
||||||||
2002
5.70% notes due
2007
|
February
|
$ |
100
|
$ |
-
|
|||
Senior
notes due
2007
|
May
|
250
|
-
|
|||||
CIPS:
|
||||||||
7.05%
First mortgage bonds due
2006
|
June
|
-
|
20
|
|||||
CILCORP:
|
||||||||
9.375%
Senior notes due
2029
|
March/April
|
-
|
12
|
|||||
CILCO:
|
||||||||
7.50%
First mortgage bonds due
2007
|
January
|
50
|
-
|
|||||
IP:
|
||||||||
Note
payable to IP
SPT:
|
||||||||
5.65%
Series due
2008
|
Various
|
43
|
-
|
|||||
5.54%
Series due
2007
|
Various
|
-
|
54
|
|||||
Total
Ameren long-term debt redemptions, repurchases and
maturities
|
$ |
443
|
$ |
86
|
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, 2007:
Effective
Date
|
Authorized
Amount
|
Issued
|
Available
|
|||||||||
Ameren
|
June
2004
|
$ |
2,000
|
$ |
459
|
$ |
1,541
|
|||||
UE
|
October
2005
|
1,000
|
685
|
315
|
||||||||
CIPS
|
May
2001
|
250
|
211
|
39
|
In
March 2004, the SEC declared
effective a Form S-3 registration statement filed by Ameren in February
2004,
authorizing the offering of 6 million additional shares of its common
stock
under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option,
newly issued shares, treasury shares, or shares purchased in the open
market or
in privately negotiated transactions. Ameren is currently selling newly
issued
shares of its common stock under DRPlus.
Ameren
is also currently selling newly
issued shares of its common stock under certain of its 401(k) plans pursuant
to
effective SEC Form S-8 registration statements. Under DRPlus and its
401(k)
plans, Ameren issued a total of 0.9 million new shares of common stock
valued at $48 million in the six months ended June 30, 2007.
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 bemade
only
by means of a prospectus that meets the requirements of the Securities
Act of
1933 and the rules and regulations thereunder.
Indebtedness
Provisions and Other Covenants
See
Note 3 – Credit Facilities and
Liquidity to our financial statements under Part I, Item 1, of this report
for a
discussion of the covenants and provisions contained in our bank credit
facilities and applicable cross-default provisions. Also
see
Note 4 – Long-term Debt and Equity Financings to our financial statements under
Part I, Item 1, of this report for a discussion of covenants and provisions
contained in certain of the Ameren Companies’ indenture agreements and articles
of incorporation.
At
June 30, 2007, 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.
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
73
capital
markets or make our access to the capital markets uncertain or limited.
Such
events would increase our cost of capital and adversely affect our ability
to
access the capital markets.
Dividends
The
amount and timing of dividends
payable on Ameren’s common stock are within the sole discretion of Ameren’s
board of directors. The board of directors has not set specific targets
or
payout parameters when declaring common stock dividends. However, the
board
considers various issues, including Ameren’s historical earnings and cash flow,
projected earnings, projected cash flow and potential cash flow requirements,
dividend payout rates at other utilities, return on investments with
similar
risk characteristics, impacts of regulatory orders or legislation and
overall
business considerations.
See
Note 3 – Credit Facilities and
Liquidity and Note 4 – Long-term Debt and Equity Financings to our financial
statements under Part I, Item 1, of this report for a discussion of covenants
and provisions contained in certain of the Ameren Companies’ financial
agreements and articles of incorporation that would restrict the Ameren
Companies’ payment of dividends in certain circumstances. At June 30, 2007,
except as discussed below with respect to the 2007 $500 million credit
facility
and the 2006 $500 million credit facility, none of these circumstances
existed
at the Ameren Companies and, as a result, they were allowed to pay
dividends.
The
2007 $500 million credit facility
and 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to
common and preferred stock dividend payments of $10 million per year each
if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first
mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have
received a below investment-grade credit rating from either Moody’s or S&P.
With respect to AERG, which currently is not rated by Moody’s or S&P, the
common and preferred stock dividend restriction will not apply if its
ratio of
consolidated total debt to consolidated operating cash flow, pursuant
to a
calculation defined in the facilities, is less than or equal to 3.0 to
1. On
July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured credit rating to
below investment-grade, causing it to be subject to this dividend payment
limitation. As of June 30, 2007, AERG did not meet the debt-to-operating
cash
flow ratio test in the 2007 and 2006 $500 million credit facilities.
The other
borrowers thereunder are not currently limited in their dividend payments
by
this provision of the 2007 or 2006 $500 million credit facilities.
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, 2007
and 2006.
Six
Months
|
|||||||
2007
|
2006
|
||||||
UE
|
$ |
127
|
$ |
84
|
|||
CIPS
|
-
|
25
|
|||||
Genco
|
113
|
71
|
|||||
CILCORP(a)
|
-
|
50
|
|||||
Nonregistrants
|
23
|
30
|
|||||
Dividends
paid by Ameren
|
$ |
263
|
$ |
260
|
(a)
|
CILCO
paid to CILCORP dividends of $50 million for the six months ended
June 30, 2006.
|
Contractual
Obligations
For
a complete listing of our
obligations and commitments, see Contractual Obligations under Part II,
Item 7
and Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form
10-K, and Other Obligations in Note 8 – Commitments and Contingencies under Part
I, Item 1, of this report. See Note 11 – Retirement Benefits to our financial
statements under Part I, Item 1, of this report for information regarding
expected minimum funding levels for our pension plan. See also Note 1
– Summary
of Significant Accounting Policies to our financial statements under
Part I,
Item 1, of this report for the unrecognized tax benefits under the provisions
of
FIN 48.
Subsequent
to December 31, 2006,
obligations related to the procurement of natural gas and nuclear fuel
materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP
to $4,031
million, $731 million, $415 million, $71 million, $1,241 million, $1,241
million
and $1,554 million, respectively, as of June 30, 2007. Total other obligations
at June 30, 2007, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP
were $6,020
million, $2,017 million, $440 million, $315 million, $1,395 million,
$1,395
million and $1,686 million, respectively.
As
a result of the Illinois electric
agreement reached in July 2007 and subject to enactment of legislation
contemplated by the agreement, the Ameren Illinois Utilities, Genco and
AERG
agreed to make aggregate contributions of $150 million over a four-year
period,
with $60 million coming from the Ameren Illinois Utilities (CIPS - $21
million;
CILCO
-
$11 million;
IP
- $28
million), $62 million from Genco and $28 million from AERG. See Note
2 – Rate
and Regulatory Matters under Part I, Item 1, of this report for additional
information regarding the Illinois electric agreement.
74
Credit Ratings
The
following table presents the principal credit ratings of the Ameren
Companies by
Moody’s, S&P and Fitch effective on the date of this
report:
Moody’s
|
S&P
|
Fitch
|
|
Ameren:
|
|||
Issuer/corporate
credit rating
|
Baa2
|
BBB-
|
BBB+
|
Unsecured
debt
|
Baa2
|
BB+
|
BBB+
|
Commercial
paper
|
P-2
|
A-3
|
F2
|
UE:
|
|||
Issuer/corporate
credit rating
|
Baa1
|
BBB-
|
A-
|
Secured
debt
|
A3
|
BBB-
|
A+
|
Commercial
paper
|
P-2
|
A-3
|
F2
|
CIPS:
|
|||
Issuer/corporate
credit rating
|
Ba1
|
BB
|
BB+
|
Secured
debt
|
Baa3
|
BBB-
|
BBB
|
Genco:
|
|||
Issuer/corporate
credit rating
|
-
|
BBB-
|
BBB+
|
Unsecured
debt
|
Baa2
|
BBB-
|
BBB+
|
CILCORP:
|
|||
Issuer/corporate
credit rating
|
-
|
BB
|
BB+
|
Unsecured
debt
|
Ba2
|
B+
|
BB+
|
CILCO:
|
|||
Issuer/corporate
credit rating
|
Ba1
|
BB
|
BB+
|
Secured
debt
|
Baa2
|
BBB-
|
BBB
|
IP:
|
|||
Issuer/corporate
credit rating
|
Ba1
|
BB
|
BB+
|
Secured
debt
|
Baa3
|
BBB-
|
BBB
|
On
March
12, 2007, Moody’s downgraded the credit ratings of Ameren, UE, CIPS, CILCORP,
CILCO, and IP. In addition, Moody’s assigned to CILCORP a corporate family
credit rating of “Ba1” and a probability of default rating of “Ba1.” Moody’s
indicated that the ratings of Ameren, CIPS, CILCORP, CILCO and IP remain
on
review for possible further downgrade. Moody’s also placed Ameren’s “Prime-2”
short-term credit rating for commercial paper on review for possible
downgrade.
The ratings of UE are no longer on review although the rating outlook
is
negative.
Moody’s
indicated that the downgrade of the ratings of Ameren, CIPS, CILCORP,
CILCO and
IP was prompted by the passage of rate freeze legislation by both the
Illinois
House of Representatives on March 6, 2007, and the Environment and Energy
Committee of the Illinois Senate on March 7, 2007, and the growing support
at
the time for a rate freeze in both chambers of the Illinois General Assembly.
In
the event of the passage and enactment of rate freeze legislation, Moody’s
indicated that the Ameren Illinois Utilities could be downgraded further
into
speculative (junk) grade.
Moody’s
indicated that the downgrade of UE was prompted by higher costs, lower
financial
metrics and a continued challenging regulatory environment in Missouri.
The
downgrade also reflects Moody’s expectation that Ameren may have to rely more
heavily on UE for upstreamed dividends if rate freeze legislation is
passed and
enacted in Illinois.
On
April
24, 2007, Moody’s stated that the passage of rate freeze legislation by the
Illinois Senate on April 20, 2007, was a negative development although
it will
not have an immediate impact on the credit ratings of Ameren or the Ameren
Illinois Utilities. The legislation would have rolled back electric rates
to
2006 levels, frozen rates at those levels for at least one year, and
provided
for refunds to customers. Moody’s also stated that any progress toward passage
of the legislation by the Illinois House of Representatives could result
in a
ratings downgrade of the Ameren Illinois Utilities. Further, Moody’s said that
enactment into law of such legislation could result in multi-notch downgrades
of
the ratings of the Ameren Illinois Utilities well into speculative grade
due to
concerns about the impact on the financial performance of the Ameren
Illinois
Utilities.
On
March
9, 2007, S&P issued a report in response to the passage by the Environment
and Energy Committee of the Illinois Senate of legislation which would
have
rolled back rates to 2006 levels and frozen rates for at least six months.
S&P indicated in its report that if such bill was passed by the full Senate,
the issuer credit ratings on the Ameren Illinois Utilities would be immediately
lowered to “BB+.” According to S&P, such a downgrade would reflect growing
sentiment in both chambers of the Illinois General Assembly of the need
for rate
relief for certain affected customers of the Ameren Illinois Utilities.
S&P
indicated that it would further lower the ratings on the Ameren Illinois
Utilities if rate freeze legislation “of any meaningful length” is approved by
both chambers of the Illinois General Assembly, and such ratings may
be lowered
precipitously in such circumstance.
On
April
23, 2007, S&P lowered its long-term corporate credit ratings of Ameren, UE,
and Genco from “BBB” to “BBB-”. Issuer credit ratings at CIPS,
CILCORP, CILCO, and IP were lowered from “BBB-” to “BB” and secured debt ratings
were lowered at CIPS and CILCO from “BBB” to “BBB-”. The downgrades followed the
passage of rate rollback and freeze legislation on April 20, 2007, by
the
Illinois Senate as discussed above.
On
April 2, 2007, Fitch downgraded
the issuer default ratings of Ameren from “A-” to “BBB+” and the issuer default
ratings of each of CIPS, CILCORP and CILCO from “BBB+” to “BB+”. Additionally,
Ameren’s and CILCORP’s senior unsecured debt ratings were lowered from “A-” to
“BBB+” and from “BBB+” to “BB+”, respectively. CIPS’ and CILCO’s secured debt
ratings were each lowered from “A” to “BBB”. Fitch stated that the downgrade of
CIPS, CILCORP and CILCO “follows the inability of the Illinois utilities to
reach an agreement concerning the recovery of purchased power costs with
the
Illinois Senate before it adjourned before the mid-term break” on March 30,
2007, and that the downgrade of Ameren was “based upon an increased overall
corporate risk profile due to the regulatory environment in
Illinois.”
75
In
July 2007, an electric settlement agreement was
reached among key stakeholders in Illinois which, subject to enactment of
enabling legislation, resolves the Illinois regulatory and legislative
uncertainties that were the basis of most of the adverse ratings actions
noted
above. See Note 2 – Rate and Regulatory Matters to our financial statements
under Part I, Item 1 of this report for a discussion of the Illinois
agreement.
Any
adverse change in the Ameren
Companies’ credit ratings may reduce access to capital and trigger additional
collateral postings and prepayments. They may also increase the cost
of
borrowing and fuel, power and gas supply, among other things, resulting
in a
negative impact on earnings. Collateral postings and prepayments made
as of the
end of the second quarter of 2007 were $87 million, $3 million, $10
million, $2 million, $24 million, $24 million, and $43 million at Ameren,
UE,
CIPS, Genco, CILCORP, CILCO and IP, respectively, resulting from our
reduced
corporate and issuer credit ratings. Sub-investment-grade issuer ratings
for
securities (less than “BBB-” or “Baa3”) at June 30, 2007, could have resulted in
Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post
additional
collateral or other assurances for certain trade obligations amounting
to
$149
million, $39 million, $19 million, $25 million, $21 million, $21 million,
or $27
million, respectively. In addition, the cost of borrowing under our credit
facilities can increase or decrease depending upon the credit ratings
of the
borrower. 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 events and trends
that may affect the Ameren Companies’ financial condition, results of
operations, or liquidity in 2007 and beyond.
Revenues
·
|
In
2006, electric rate freezes or adjustment moratoriums and power
supply
contracts expired in Ameren’s regulatory jurisdictions. At the end of
2006, electric rates for Ameren’s operating subsidiaries had been fixed or
declining for periods ranging from 15 years to 25
years.
|
·
|
Average
residential electric rates for CIPS, CILCO and IP increased
significantly
following the expiration of a rate freeze at the end of 2006.
Electric
rates rose because of the increased cost of power purchased
on behalf of
the Ameren Illinois Utilities’ customers and an increase in electric
delivery service rates. Illinois average residential rates
were expected
to increase in 2007 by approximately 40% to 55% over 2006 rates
with the
overall increase for electric heat customers expected to be
even higher.
Due to the magnitude of these increases, a comprehensive customer
rate
relief and customer assistance program and agreement was reached
with key
stakeholders in Illinois that would provide approximately $1
billion of
funding for rate relief for certain electric customers in Illinois,
including approximately $488 million to customers of the Ameren
Illinois
Utilities. This agreement was reached in order to avoid rate
rollback and
freeze legislation, or a tax on power generation enabling legislation
necessary for the agreement to become effective was passed
by the Illinois
General Assembly in late July 2007 but must be signed by the
governor of
Illinois to become law.
|
·
|
Pursuant
to the rate relief program, the Ameren Illinois Utilities,
Genco and AERG
agreed to make aggregate contributions of $150 million over
a four-year
period, with
$60
million coming from the Ameren Illinois Utilities (CIPS - $21
million;
CILCO - $11 million; IP - $28 million), $62 million from Genco
and $28
million from AERG. To fund these contributions, the Ameren
Illinois
Utilities, Genco and AERG would need to increase their respective
short-term or long-term borrowings.
|
·
|
Under
the rate relief program, the Ameren Illinois Utilities would
continue to
have the right to file new electric delivery service rate cases
with the
ICC at the utilities’ discretion. As a result of low returns on equity
expected in 2007, the Ameren Illinois Utilities plan to file
additional
delivery service rate cases by the end of
2007.
|
·
|
The
redesign of all-electric customers’ rates is the subject of an ongoing
case with the ICC designed to reduce seasonal fluctuations
for residential
customers who use large amounts of electricity while allowing
utilities to
fully recover costs. However, the redesign is expected to result
in
revenue changes between quarterly reporting
periods.
|
·
|
The
agreement provides that if legislation is enacted in Illinois
before
August 1, 2011, freezing or reducing retail electric rates
or imposing or
authorizing a new tax, special assessment or fee on the generation
of
electricity, then the remaining commitments would expire and
any funds set
aside in support of the funding commitments would be refunded
to the
contributing utilities and electric
generators.
|
·
|
As
part of the agreement, the current reverse auction used for
power
procurement in Illinois would be discontinued immediately and
replaced
with a new power procurement process. In 2008, utilities would
contract
for necessary baseload, intermediate and peaking power requirements
through a request-for-proposal process, subject to ICC review
and
approval. Existing supply contracts from the September 2006
reverse
auction would remain in place.
|
·
|
As
part of the rate relief program, the Ameren Illinois Utilities
entered
into financial contracts with Marketing Company (for the benefit
of Genco
and AERG), to lock-in prices for 400 to 1,000 megawatts annually
of their
baseload power requirements from 2008 through 2012 at
|
76
|
relevant
market prices. These contracts are not effectiveuntil enactment
of
enabling legislation by the Illinois governor. If the legislation
is
enacted into law after August 10, 2007, then new market prices
will be set
when the legislation is enacted. These financial swap contracts
expose
Genco and AERG to changes in market prices, which could materially
impact
Genco’s, CILCORP’s, and CILCO’s results of operations, financial position,
or liquidity if the market prices of power exceed the locked-in
prices.
|
·
|
See
Note 2 – Rate and Regulatory Matters to our financial statements under
Part I, Item 1, of this report for a further discussion of
Illinois rate
matters.
|
·
|
The
MoPSC issued an order granting UE a $43 million increase in
base rates for
electric service with new electric rates effective June 4,
2007. The MoPSC
also approved a stipulation and agreement authorizing an increase
in UE’s
annual natural gas delivery revenues of $6 million, effective
April 1,
2007. UE agreed not to file a natural gas delivery rate case
before March
15, 2010. With increasing fuel and purchased power costs, and
lacking a
fuel and purchased power cost recovery mechanism, coupled with
increased
capital and operations and maintenance expenditures targeted
at enhanced
distribution system reliability, UE expects to be entering
a period where
more frequent rate cases will be
necessary.
|
·
|
Very
volatile power prices in the Midwest affect the amount of revenues
Ameren,
UE, Genco and CILCO (through AERG) can generate by marketing
power into
the wholesale and spot markets and influence the cost of power
purchased
in the spot markets.
|
·
|
In
2006, the Non-rate-regulated Generation segment generated 30
million
megawatthours of power (Genco - 15 million, AERG - 7 million,
EEI - 8
million). Power previously supplied by Genco to CIPS (through
Marketing
Company) and by AERG to CILCO was subject to below-market-priced contracts
that expired on December 31, 2006. All but 5 million megawatthours
of
Genco’s pre-2006 wholesale and retail electric power supply agreements
also expired during 2006. In 2007, an additional 1 million
megawatthours
of these contracts will expire and another 2 million contracted
megawatthours will expire in 2008. These agreements had an
average
embedded selling price of $36 per megawatthour, which is below
current
market prices. In 2006, Genco also sold 2.1 million net megawatthours
of
power in the spot market at an average market price of $38
per
megawatthour. In 2006, AERG’s power was sold principally to CILCO, at an
average price of $32 per megawatthour. In addition, AERG sold
1.5 million
net megawatthours of power in the spot market at an average
price of $37
per megawatthour in 2006. The Non-rate-regulated Generation
segment
expects to generate 32 million megawatthours of power in 2007
(Genco – 17
million,
AERG
– 7 million, EEI – 8 million).
|
·
|
The
marketing strategy for Non-rate-regulated Generation is to
optimize
generation output in a low risk manner to minimize earnings
and cash flow
volatility, while capitalizing on its low-cost generation fleet
to provide
for solid, sustainable returns. Through a mix of physical and
financial
sales contracts and the Illinois 2006 power procurement auction
and
including expected contracts associated with the Illinois settlement
agreement referenced above, the Non-rate-regulated Generation
segment has
sold approximately 90% of its expected 2007 generation output
for the
remainder of 2007 (fiscal year 2008 - 70%, or 23 million megawatthours;
fiscal year 2009 - 50%, or 17 million megawatthours) at an
average price
of $51 per megawatthour. Expected sales in 2007 include an
estimated 7.6
million megawatthours of power sold through the Illinois power
procurement
auction at about $65 per megawatthour (2008 – 6.8 million, 2009 – 4.3
million).
|
·
|
We
expect continued economic growth in our service territory to
benefit
energy demand in 2007 and beyond, but higher energy prices
could result in
reduced demand from customers, especially in
Illinois.
|
·
|
UE,
Genco and CILCO are seeking to raise the equivalent availability
and
capacity factors of their power plants through greater investments
and a
process improvement program and
investment.
|
Fuel
and Purchased Power
·
|
In
2006, 85% of Ameren's electric generation (UE - 77%, Genco
- 97%,
CILCO - 99%) was supplied by its coal-fired power plants. About
93% of the coal used by these plants (UE - 97%, Genco - 87%,
CILCO - 69%)
was delivered by railroads from the Powder River Basin in
Wyoming.
In the past, deliveries from the Powder River Basin have
been restricted
because of rail maintenance, weather and derailments. As of June 30,
2007, coal inventories for UE, Genco, AERG and EEI were adequate,
and
consistent with historical levels. Disruptions in coal deliveries
could cause UE, Genco, AERG and EEI to pursue a strategy
that could
include reducing sales of power during low-margin periods,
buying
higher-cost fuels to generate required electricity, and purchasing
power
from other sources.
|
·
|
Ameren’s
coal and related transportation costs are expected to increase
15% to 20%
in 2007 over 2006 and 5% to 10% in 2008. Ameren’s nuclear fuel costs are
also expected to rise over the next few years. 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 in Part I of this report for information
about the
percentage of fuel and transportation requirements that are
price-hedged
for 2007 through 2011.
|
77
·
|
In
Illinois, Ameren and IP will also experience higher year-over-year
purchased power expenses as the amortization of certain favorable
purchase
accounting adjustments associated with the IP acquisition was
completed in
2006.
|
·
|
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. In UE’s electric rate order issued by the MoPSC
in May 2007, the MoPSC denied UE’s request to implement a fuel and
purchased power cost recovery mechanism and an environmental
cost recovery
mechanism. UE may request the use of these mechanisms in future
rate
cases.
|
·
|
In
2007, Ameren expects to reduce levels of emission allowance
sales in order
to retain remaining allowances for future environmental compliance
needs.
|
Other
Costs
·
|
In
December 2005, there was a breach of the upper reservoir at
UE’s Taum Sauk
pumped-storage hydroelectric facility. This resulted in significant
flooding in the local area, which damaged a state park. In
February 2007,
UE submitted plans and an environmental report to FERC to rebuild
the
upper reservoir at its Taum Sauk plant, assuming successful
resolution of
outstanding issues with authorities of the state of Missouri.
Should the
decision be made to rebuild the Taum Sauk plant, UE would expect
it to be
out of service through at least the middle of 2009, if not
longer. UE has
accepted responsibility for the effects of the incident. At
this time, UE
believes that substantially all of the damage and liabilities
(but not
penalties or lost electric margins) caused by the breach, including
rebuilding the plant, will be covered by insurance. 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 is engaged
in
litigation initiated by certain private parties and by state
authorities.
The Taum Sauk incident is also under investigation at the MoPSC.
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. See Note 2 – Rate and Regulatory Matters and
Note 8 - Commitments and Contingencies to our financial statements
under
Part I, Item 1, of this report for a further discussion of
Taum Sauk
matters.
|
·
|
UE’s
Callaway nuclear plant’s next scheduled refueling and maintenance outage
is in the fall of 2008. During an outage, which occurs every
18 months,
maintenance and purchased power costs increase, and the amount
of excess
power available for sale decreases, versus non-outage
years.
|
·
|
Over
the next few years, we expect rising employee benefit costs
as well as
higher insurance and security costs associated with additional
measures we
have taken, or may need to take, at UE’s Callaway nuclear plant and at our
other facilities. Insurance premiums may also increase as a
result of the
Taum Sauk incident, among other
things.
|
·
|
Bad
debts may increase due to rising electric
rates.
|
·
|
We
are currently undertaking cost reduction and control initiatives
associated with the strategic sourcing of purchases and streamlining
of
all aspects of our business.
|
Capital
Expenditures
·
|
The
EPA has issued more stringent emission limits on all coal-fired
power
plants. Between 2007 and 2016, Ameren expects that certain
Ameren
Companies will be required to invest between $3.5 billion and
$4.5 billion
to retrofit their power plants with pollution control equipment.
These
investments will also result in decreased plant availability
during
construction and significantly higher ongoing operating expenses.
Approximately 50% of this investment will be in Ameren’s regulated UE
operations, and it is therefore 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.
|
·
|
Ameren
will provide a report on how it is responding to rising regulatory,
competitive, and public pressure to significantly reduce carbon
dioxide
and other emissions from current and proposed power plant operations.
The
report will include Ameren’s climate change strategy and activities,
current greenhouse gas emissions, and analysis with respect
to plausible
future greenhouse gas scenarios. Ameren will publish this report
on its
Web site by December 15, 2007. Investments to control carbon
emissions at
Ameren’s coal-fired plants would significantly increase future capital
expenditures.
|
·
|
UE
continues to evaluate its longer-term needs for new baseload
and peaking
electric generation capacity. At this time, UE does not expect
to require
new baseload generation capacity until at least 2018. However,
due to the
significant time required to plan, acquire permits for and
build a
baseload power plant, UE is actively studying future plant
alternatives,
including those that would use coal or nuclear fuel. In 2007,
UE signed an
agreement with UniStar Nuclear to assist UE in the preparation
of a
combined construction and operating license application (COLA)
for filing
with the NRC. A COLA describes how a nuclear plant would be
designed,
constructed and operated. In addition, UE has also signed contracts
for
certain long lead-time equipment. Preparing a COLA and entering
into these
contracts does not mean a decision has been made to build a
nuclear plant.
They are only the first steps in the regulatory licensing and
procurement
process. UE and UniStar Nuclear must submit the
COLA
|
78
|
to
the NRC in 2008 to be eligible for incentives available
under provisions
of the 2005 Energy Policy
Act.
|
·
|
Over
the next few years, we expect to make significant investments
in our
electric and gas infrastructure to improve overall system reliability
in
addition to addressing environmental compliance requirements.
We are
projecting higher labor and material costs for these capital
expenditures.
|
Other
·
|
Severe
storms in 2006 and early 2007 resulted in electric outages
for more than
1.5 million customers and an increased focus on alternatives
for improving
reliability during severe storms. UE, CIPS, CILCO and IP are
studying
alternatives to improve system reliability, which could result
in
increased investment in system infrastructure or higher maintenance
expenses. UE announced in July 2007 plans to spend $300 million
over three
years for underground cabling and reliability improvement,
$135 million
($45 million per year) for tree-trimming, and $84 million over
three years
(approximately $28 million per year) for circuit and device
inspection and
repair. We would expect any additional costs or investments
to be
recovered in rates.
|
·
|
The
MoPSC has initiated a rulemaking process to develop reliability
rules
applicable to Missouri investor-owned utilities that address
three focus
areas: vegetation management, infrastructure inspection, and
reliability.
The MoPSC’s proposed vegetation management and infrastructure inspection
rules were published in the Missouri Register in July 2007,
and a public
hearing on these rules is scheduled for August 15, 2007. The
MoPSC’s
proposed reliability rules have not yet been published in the
Missouri
Register. The ultimate cost of the rules is subject to their
final terms,
but could be material. UE anticipates that most of such costs
would
ultimately be recoverable in rates.
|
·
|
In
2006, Ameren realized gains on sales of noncore properties,
including
leveraged leases. The net benefit of these sales to Ameren
in 2006 was 16
cents per share. Ameren continues to pursue the sale of its
interests in
its remaining three leveraged lease assets. Ameren does not
expect to
achieve similar sales levels of noncore properties in
2007.
|
Affiliate
Transactions
·
|
As
a result of the termination of the JDA on December 31, 2006,
UE and Genco
no longer have the obligation to provide power to each other.
UE is able
to sell any excess power it has at market prices, which we
believe will
most likely be higher than the prices paid to it by Genco.
Genco will no
longer receive the margins on sales that it made, which were
fulfilled
with power from UE. The electric rate order issued in May 2007
by the
MoPSC incorporated the net decrease in UE’s revenue requirement from
increased margins expected to result from the termination of
the JDA. See
Note 7 – Related Party Transactions to our financial statements under
Part
I, Item 1, of this report for a discussion of the effects of
terminating
the JDA.
|
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
nonderivative, 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. The following discussion of our risk management activities includes
forward-looking statements that involve risks and uncertainties. Actual
results
could differ materially from those projected in the forward-looking statements.
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
composed of senior-level Ameren officers.
79
Except
as discussed below, there have
been no material changes to the quantitative and qualitative disclosures
about
market risk in the Form 10-K. See Item 7A under Part II of the 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,
2007:
Interest
Expense
|
Net
Income(a)
|
||||||
Ameren
|
$ |
24
|
$ |
(15)
|
|||
UE
|
9
|
(6)
|
|||||
CIPS
|
2
|
(1)
|
|||||
Genco
|
2
|
(1)
|
|||||
CILCORP
|
5
|
(3)
|
|||||
CILCO
|
3
|
(2)
|
|||||
IP
|
7
|
(4)
|
(a)
|
Calculations
are based on an effective tax rate of
38%.
|
The
estimated changes above do 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. In 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 receivable and executory contracts with market risk exposures.
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, 2007, no nonaffiliated customer represented more than 10%, in
the
aggregate, of our accounts receivable. Our revenues are primarily derived
from
sales or delivery of electricity and natural gas to customers in Missouri
and
Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company
may have
credit exposure associated with power purchase and sale activity with
nonaffiliated companies. These companies also have credit exposure to
affiliates. At June 30, 2007, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’
and Marketing Company’s combined credit exposure to nonaffiliated
non-investment-grade purchases and sales was each less than $1
million, net of collateral (2006 - less than $1 million). We establish
credit
limits for these counterparties and monitor the appropriateness of these
limits
on an ongoing basis through a credit risk management program that involves
daily
exposure reporting to senior management, master trading and netting agreements,
and credit support, such as letters of credit and parental guarantees.
We also
analyze each counterparty’s financial condition before we enter into sales,
forwards, swaps, futures or option contracts, and we monitor counterparty
exposure associated with our leveraged leases. We estimate our credit
exposure
to MISO associated with the MISO Day Two Energy Market to be $33 million
at June
30, 2007 (2006 - $27 million).
The
Ameren Illinois Utilities will be
exposed to credit risk in the event of nonperformance by the parties
contributing to the Illinois comprehensive rate relief and assistance
programs,
which would provide $488 million in rate relief over a four-year period
to
certain electric customers of the Ameren Illinois Utilities, if enabling
legislation is enacted into law. Under funding agreements among the parties
contributing to the rate relief and assistance programs, at the end of
each
month, the Ameren Illinois Utilities would bill the participating generators
for
their proportionate share of that month’s rate relief and assistance, which
would be due in 30 days, or drawn from the escrow agreement. See Note
2 – Rate
and Regulatory Matters to our financial statements under Part I, Item
1 of this
report for additional information.
Equity
Price Risk
Our
costs
of providing defined benefit retirement and postretirement benefit plans
are
dependent upon 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. Genco, AERG and EEI also seek
to sell
power forward to wholesale, municipal and industrial customers to limit
exposure
to changing prices. 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). However, a portion of the generation capacity of UE,
Genco,
AERG and EEI is not contracted through physical or financial hedge arrangements
and is therefore exposed to volatility in market prices.
80
The
following table shows how our
earnings might decrease if power prices were to increase by 1% on unhedged
economic generation for the remainder of 2007 through 2010:
Net
Income
|
|||
Ameren
|
$ |
(25)
|
|
UE
|
(10)
|
||
Genco
|
(10)
|
||
CILCO
(AERG)
|
(3)
|
||
EEI
|
(2)
|
a)
|
Calculations
are based on an effective tax rate of
38%
|
Similar
techniques are used to manage
risks associated with fuel exposures for generation. Most UE, Genco,
AERG and
EEI fuel supply contracts are physical forward contracts. UE, Genco,
AERG and
EEI do not have a provision similar to the PGA clause for electric operations,
so UE, Genco, AERG and EEI have entered into long-term contracts with
various
suppliers to purchase coal and nuclear fuel to manage their exposure
to fuel
prices. The coal hedging strategy is intended to secure a reliable coal
supply
while reducing exposure to commodity price volatility. Price and volumetric
risk
mitigation is accomplished primarily through periodic bid procedures,
whereby
the amount of coal purchased is determined by the current market prices
and the
minimum and maximum coal purchase guidelines for the given year. We generally
purchase coal up to five years in advance, but we may purchase coal beyond
five
years to take advantage of favorable deals or market conditions. The
strategy
also allows for the decision not to purchase coal to avoid unfavorable
market
conditions. As part of its electric rate case filed in July 2006, UE
had
requested approval by the MoPSC for a fuel and purchased power cost recovery
mechanism; however, such request was rejected by the MoPSC in its May
2007
order.
Transportation
costs for coal and
natural gas can be a significant portion of fuel costs. We typically
hedge coal
transportation forward to provide supply certainty and to mitigate
transportation price volatility. The natural gas transportation expenses
for the
distribution utility companies and the gas-fired generation units are
controlled
by FERC via published tariffs with rights to extend the contracts from
year to
year. Depending on our competitive position, we are able in some instances
to
negotiate discounts to these tariffs for our requirements.
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 no generation, that are
price-hedged over the remainder of 2007 through 2011:
2007
|
2008
|
2009
–
2011
|
|||||||||
Ameren:
|
|||||||||||
Coal
|
100%
|
95%
|
40%
|
||||||||
Coal
transportation
|
100
|
95
|
46
|
||||||||
Nuclear
fuel
|
100
|
91
|
52
|
||||||||
Natural
gas for generation
|
55
|
12
|
-
|
||||||||
Natural
gas for distribution(a)
|
(a)
|
31
|
9
|
||||||||
Purchased
power for Illinois Regulated(b)
|
100
|
81
|
21
|
||||||||
UE:
|
|
||||||||||
Coal
|
100%
|
94%
|
41%
|
||||||||
Coal
transportation
|
100
|
97
|
61
|
||||||||
Nuclear
fuel
|
100
|
91
|
52
|
||||||||
Natural
gas for generation
|
36
|
8
|
-
|
||||||||
Natural
gas for distribution(a)
|
(a)
|
32
|
5
|
||||||||
CIPS:
|
|
||||||||||
Natural
gas for distribution(a)
|
(a)
|
32%
|
13%
|
||||||||
Purchased
power(b)
|
100%
|
81
|
21
|
||||||||
Genco:
|
|
||||||||||
Coal
|
100%
|
95%
|
38%
|
||||||||
Coal
transportation
|
100
|
97
|
45
|
||||||||
Natural
gas for generation
|
100
|
15
|
-
|
||||||||
CILCORP/CILCO:
|
|||||||||||
Coal
(AERG)
|
99%
|
96%
|
41%
|
||||||||
Coal
transportation (AERG)
|
100
|
71
|
23
|
||||||||
Natural
gas for distribution(a)
|
(a)
|
24
|
7
|
||||||||
Purchased
power(b)
|
100
|
81
|
21
|
||||||||
IP:
|
|||||||||||
Natural
gas for distribution(a)
|
(a)
|
35%
|
9%
|
||||||||
Purchased
power(b)
|
100%
|
81
|
21
|
81
2007
|
2008
|
2009
–
2011
|
|||||||||
EEI:
|
|||||||||||
Coal
|
100%
|
97%
|
42%
|
||||||||
Coal
transportation
|
100
|
100
|
-
|
(a)
|
The
year 2007 is non-applicable for this table. The year 2008 represents
November 2007 through March 2008. This continues each successive
year
through March 2011.
|
(b)
|
Represents
the percentage of purchased power price-hedged for fixed-price
residential
and small commercial customers with less than 1 megawatt of
demand as part
of the Illinois power procurement auction held in early September
2006. Excluded from the percent hedged amount is purchased power
for
fixed-price large commercial and industrial customers with
1 megawatt of
demand or higher. Nearly all of these customers chose a third-party
supplier. However, regardless of whether customers choose a
third-party
supplier, the purchased power needed to serve this load is
100%
price-hedged through May 31, 2008, due to the Illinois auction. Also
excluded from the percent hedged amount is purchased power
to serve large
service real-time pricing customers. See Note 2 – Rate and Regulatory
Matters and Note 8 – Commitments and Contingencies to our financial
statements under Part I, Item 1, of this report for a discussion
of this
matter.
|
The
following table shows how our total
fuel expense might increase and how our net income might decrease if
coal and
coal transportation costs were to increase by 1% on any requirements
not
currently covered by fixed-price contracts for the five-year period 2007
through
2011:
Coal
|
Transportation
|
||||||||||||||
Fuel
Expense
|
Net
Income(a)
|
Fuel
Expense
|
Net
Income(a)
|
||||||||||||
Ameren(b)
|
$ |
12
|
$ | (8 | ) | $ |
14
|
$ | (9 | ) | |||||
UE
|
6
|
(4 | ) |
5
|
(3 | ) | |||||||||
Genco
|
4
|
(2 | ) |
4
|
(2 | ) | |||||||||
CILCORP
|
2
|
(1 | ) |
2
|
(1 | ) | |||||||||
CILCO
(AERG)
|
2
|
(1 | ) |
2
|
(1 | ) | |||||||||
EEI
|
1
|
(1 | ) |
4
|
(2 | ) |
(a)
|
Calculations
are based on an effective tax rate of
38%.
|
(b)
|
Includes
amounts for Ameren registrant and nonregistrant
subsidiaries.
|
In
the
event of a significant change in coal and coal transportation prices,
UE, Genco,
AERG and EEI 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.
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 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, 2007. The sources used
to
determine the fair value of these contracts were active quotes, other
external
sources, and other modeling and valuation methods. All of these contracts
have
maturities of less than five years.
Ameren(a)
|
UE
|
CIPS
|
Genco(b)
|
CILCORP/
CILCO
|
IP
|
|||||||||||||||||||
Three
Months
|
||||||||||||||||||||||||
Fair
value of contracts at beginning of period, net
|
$ |
31
|
$ |
-
|
$ |
3
|
$ | (1 | ) | $ |
6
|
$ |
-
|
|||||||||||
Contracts
realized or otherwise settled during the period
|
(5 | ) | (2 | ) | (1 | ) |
-
|
(2 | ) |
-
|
||||||||||||||
Changes
in fair values attributable to changes in valuation technique
and
assumptions
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Fair
value of new contracts entered into during the period
|
22
|
(2 | ) |
-
|
-
|
-
|
-
|
|||||||||||||||||
Other
changes in fair value
|
21
|
9
|
(1 | ) | (1 | ) |
-
|
-
|
||||||||||||||||
Fair
value of contracts outstanding at end of period, net
|
$ |
69
|
$ |
5
|
$ |
1
|
$ | (2 | ) | $ |
4
|
$ |
-
|
|||||||||||
Six
Months
|
||||||||||||||||||||||||
Fair
value of contracts at beginning of period, net
|
$ |
98
|
$ |
12
|
$ |
2
|
$ | (1 | ) | $ |
6
|
$ |
2
|
|||||||||||
Contracts
realized or otherwise settled during the period
|
(22 | ) | (6 | ) | (1 | ) |
-
|
(4 | ) |
-
|
||||||||||||||
Changes
in fair values attributable to changes in valuation technique
and
assumptions
|
-
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Fair
value of new contracts entered into during the period
|
20
|
(3 | ) |
-
|
-
|
-
|
-
|
|||||||||||||||||
Other
changes in fair value
|
(27 | ) |
2
|
-
|
(1 | ) |
2
|
(2 | ) | |||||||||||||||
Fair
value of contracts outstanding at end of period, net
|
$ |
69
|
$ |
5
|
$ |
1
|
$ | (2 | ) | $ |
4
|
$ |
-
|
(a)
|
Includes
amounts for Ameren registrant and nonregistrant subsidiaries
and
intercompany eliminations.
|
(b)
|
In
conjunction with the new power supply agreement between Marketing
Company
and Genco that went into effect January 1, 2007, the mark-to-market
value
of hedges entered into during 2006 for Genco was transferred
from Genco to
Marketing Company.
|
82
The
following table presents maturities of derivative contracts as of June
30,
2007:
Sources
of Fair Value
|
Maturity
Less
than
1
Year
|
Maturity
1-3
Years
|
Maturity
4-5
Years
|
Maturity
in
Excess
of
5
Years
|
Total
Fair
Value
|
||||||||||||||
Ameren:
|
|||||||||||||||||||
Prices
actively
quoted
|
$ |
8
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
8
|
|||||||||
Prices
provided by other external sources(a)
|
1
|
-
|
-
|
-
|
1
|
||||||||||||||
Prices
based on models and other valuation methods(b)
|
41
|
19
|
-
|
-
|
60
|
||||||||||||||
Total
|
$ |
50
|
$ |
19
|
$ |
-
|
$ |
-
|
$ |
69
|
|||||||||
UE:
|
|||||||||||||||||||
Prices
actively
quoted
|
$ |
2
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
2
|
|||||||||
Prices
provided by other external sources(a)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Prices
based on models and other valuation methods(b)
|
2
|
1
|
-
|
-
|
3
|
||||||||||||||
Total
|
$ |
4
|
$ |
1
|
$ |
-
|
$ |
-
|
$ |
5
|
|||||||||
CIPS:
|
|||||||||||||||||||
Prices
actively
quoted
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
|||||||||
Prices
provided by other external sources(a)
|
1
|
-
|
-
|
-
|
1
|
||||||||||||||
Prices
based on models and other valuation methods(b)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Total
|
$ |
1
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
1
|
|||||||||
Genco:
|
|||||||||||||||||||
Prices
actively
quoted
|
$ | (1 | ) | $ | (1 | ) | $ |
-
|
$ |
-
|
$ | (2 | ) | ||||||
Prices
provided by other external sources(a)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Prices
based on models and other valuation methods(b)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Total
|
$ | (1 | ) | $ | (1 | ) | $ |
-
|
$ |
-
|
$ | (2 | ) | ||||||
CILCORP/CILCO:
|
|||||||||||||||||||
Prices
actively
quoted
|
$ |
1
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
1
|
|||||||||
Prices
provided by other external sources(a)
|
3
|
-
|
-
|
-
|
3
|
||||||||||||||
Prices
based on models and other valuation methods(b)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Total
|
$ |
4
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
4
|
|||||||||
IP:
|
|||||||||||||||||||
Prices
actively
quoted
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
|||||||||
Prices
provided by other external sources(a)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Prices
based on models and other valuation methods(b)
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||
Total
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
-
|
(a)
|
Principally
fixed price for floating over-the-counter power swaps, power
forwards and
fixed price for floating over-the-counter natural gas
swaps.
|
(b)
|
Principally
coal and SO2
option values
based on a Black-Scholes model that includes information from
external
sources and our estimates. Also includes interruptible power
forward and
option contract values based on our
estimates.
|
ITEM
4. CONTROLS AND PROCEDURES.
(a)
|
Evaluation
of Disclosure Controls and
Procedures
|
As
of
June 30, 2007, evaluations were performed, under the supervision and
with the
participation of management, including the principal executive officer
and
principal financial officer of each of the Ameren Companies, of the
effectiveness of the design and operation of such registrant’s disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
of the
Exchange Act). Based upon those evaluations, the principal executive
officer and
principal financial officer of each of the Ameren Companies have concluded
that
such disclosure controls and procedures are effective to provide assurance
that
information required to be disclosed in such registrant’s reports filed or
submitted under the Exchange Act is recorded, processed, summarized and
reported
within the time periods specified in the SEC’s rules and forms and such
information is accumulated and communicated to its management, including
its
principal executive and principal financial officers, to allow timely
decisions
regarding required disclosure.
(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.
83
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 substantial 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.
For
additional information on legal and
administrative proceedings, see 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, and Item 1A, Risk Factors,
below of
this report.
ITEM
1A. RISK FACTORS.
The
Form
10-K 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 the Form 10-K.
The
electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge
are
determined through regulatory proceedings and are subject to legislative
actions
which are largely outside of our control. Where these events result in
the
inability of UE, CIPS, CILCO or IP to recover their respective costs
and earn an
appropriate return on investment, it could have a material adverse effect
on our
future results of operations, financial position or
liquidity.
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, and liquidity
of
the Ameren Companies. The electric and gas utility industry is highly
regulated.
The regulation of the rates that we charge our customers is determined,
in large
part, by governmental entities outside of our control, including the
MoPSC, the
ICC, and FERC. Decisions made by these entities could have a material
adverse effect on our results of operations, financial position, or
liquidity.
Increased
costs and investments, when
combined with rate reductions and moratoriums, have caused decreased
returns in
Ameren’s utility businesses. Ameren expects that many of its operating expenses
will continue to rise. Ameren further expects to continue to make significant
investment in its energy infrastructure. Despite the provisions of the
Illinois
rate relief agreement reached in July 2007, described below, which remains
subject to enactment of enabling legislation by the Illinois governor,
and the
rate increases granted by the MoPSC and the ICC in recent electric and
gas rate proceedings, Ameren remains subject to competitive, economic,
political, legislative and regulatory pressures that could have a material
adverse effect on our results of operations, financial position, or
liquidity.
Illinois
Electric
Delivery Service Rate Cases
A
provision of the Illinois Customer
Choice Law related to the restructuring of the Illinois electric industry
put a
rate freeze into effect through January 1, 2007, for CIPS, CILCO and
IP. CIPS,
CILCO and IP filed rate cases with the ICC in December 2005 to modify
their
electric delivery service rates effective January 2, 2007. CIPS, CILCO
and IP
requested to increase their annual revenues for electric delivery service
by
$202 million in the aggregate (CIPS - $14 million, CILCO - $43 million
and IP
- $145 million). In November 2006, the ICC issued an order that approved
an
aggregate revenue increase of $97 million effective January 2, 2007 (CIPS
- an $8 million decrease, CILCO - a $21 million increase and IP -
an $84
million increase) based on an allowed return on equity of 10%. In May
2007, the
ICC issued an order disallowing the recovery of certain administrative
and
general expenses totaling $50 million. Because of the ICC’s cost disallowances
and regulatory lag, the Ameren Illinois Utilities are not expected to
earn their
allowed return on equity of 10% in 2007. Most customers were taking service
under a frozen bundled electric rate in 2006, which included the cost
of power,
so these delivery service revenue changes do not directly correspond
to a change
in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery
service rates that became effective January 2, 2007. CIPS, CILCO and
IP expect
to file additional electric delivery service rate cases before December
31,
2007.
Electric Agreement
Consistent
with the Illinois Customer
Choice Law that froze electric rates for CIPS, CILCO and IP through January
1,
2007, these companies entered into power supply contracts that expired
on
December 31, 2006. In January 2006, the ICC approved a framework for
CIPS, CILCO
and IP to procure power for use by their customers through an auction.
It also
approved the related tariffs to
84
collect
these costs from customers for the period commencing January 2, 2007.
In
accordance with the January 2006 ICC order, a power procurement auction
was held
in September 2006.
Various
Illinois legislators, the
Illinois attorney general, the Illinois governor, and other parties challenged
the results of the auction and the structure for the recovery of costs
for power
supply resulting from the auction through rates to customers. In the
first six
months of 2007, legislation was introduced in the Illinois General Assembly
which would have rolled back and frozen the Ameren Illinois Utilities’ electric
rates at pre-January 2, 2007 levels. This would have prevented the Ameren
Illinois Utilities from recovering from retail customers substantial
portions of
the cost of electric energy the Ameren Illinois Utilities are purchasing
under
wholesale contracts entered into as a result of the September 2006 auction,
and
would have caused the Ameren Illinois Utilities to under-recover their
delivery
service costs until the ICC could approve higher delivery service
rates.
As
a result of these concerns, in
July 2007, an agreement was reached among key stakeholders in Illinois
that
addresses the increase in electric rates and the future power procurement
process. Ameren, on behalf of Marketing Company, Genco and AERG, the
Ameren
Illinois Utilities, Exelon, on behalf of Exelon Generation Company LLC,
Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary,
Dynegy Holdings, Inc., Midwest Generation, LLC, and MidAmerican Energy
Company
agreed to contribute approximately
$1
billion over four years to fund both rate relief programs and the IPA.
The
agreement provides that if legislation is enacted in Illinois before
August 1,
2011 freezing or reducing retail electric rates or imposing or authorizing
a new
tax, special assessment or fee on generation of electricity, then the
remaining
funding commitments will expire and any funds set aside in support of
those
commitments will be refunded to the utilities and electric generators.
The
agreement also provides that all pending litigation and regulatory actions
by
the Illinois attorney general relating to the reverse auction procurement
process, which was used to determine market-based rates effective January
1,
2007, and the electric space heating marketing practices of the Ameren
Illinois
utilities would be withdrawn with prejudice.
Although
we cannot fully predict the
effect of the implementation of the comprehensive rate relief program
and
agreement on Ameren, the Ameren Illinois Utilities, Genco or AERG, we
believe
the settlement agreement reached with key stakeholders in Illinois significantly
reduces the risk that legislation would be enacted into law that reduces
and
freezes electric rates of CIPS, CILCO and IP to rates that were in effect
prior
to January 2, 2007, or that imposes a tax on electric generation in Illinois.
The following factors resulting from implementation of the program and
agreement
could have a material adverse effect on the results of operations, financial
position or liquidity of Ameren, the Ameren Illinois Utilities, Genco
or
AERG:
·
|
uncertainty
as to the implementation of the new power procurement process
in Illinois
for 2008 and 2009, including ICC review and approval requirements,
the
role of the IPA, and the ability of the Ameren Illinois Utilities
to
lease, or invest in, generation
facilities;
|
·
|
the
increase in short-term or long-term borrowings by the Ameren
Illinois
Utilities, Genco and AERG to fund contributions under the program
and
agreement;
|
·
|
the
failure by the electric generators that are party to the agreement
to
perform in a timely manner under their respective funding agreements,
which permits the Ameren Illinois Utilities to seek reimbursement
for a
portion of the rate relief that will be provided to certain
of their
electric customers;
|
·
|
the
exposure of Genco and AERG to changes in market prices as a
result of the
financial swap contracts that Marketing Company (on behalf
of Genco and
AERG) entered into with the Ameren Illinois Utilities;
and
|
·
|
the
extent to which Genco and AERG will be successful in making
future sales
to supply a portion of Illinois' total electric demand through
the revised
power procurement mechanism.
|
The
settlement agreement will not be effective until enabling legislation,
which has
been passed by the Illinois General Assembly, is enacted into law by
the
Illinois governor. We are unable to predict the actions the Illinois
General Assembly, the Illinois attorney general or Illinois governor
may take that might affect electric rates, the power procurement process
for
CIPS, CILCO and IP or pending litigation and regulatory actions if
the
settlement agreement is not enacted into law. If any decision is made or
action occurs 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, and such decision or action is not promptly enjoined, it could
result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO
and IP.
These consequences could include a significant drop in credit ratings
to deep
junk (or speculative) status, the inability to access the capital markets
on
reasonable terms, higher borrowing costs, higher power supply costs,
an
inability to make timely energy infrastructure investments, requirements
to post
collateral or other assurances for certain obligations, significant
risk of
disruption in electric and gas service, significant job losses, and
the
financial insolvency and bankruptcy of CIPS, CILCORP, CILCO and IP.
In addition,
Ameren, CILCORP and IP would need to assess whether they are required
to record
a charge for
85
Missouri
With
the expiration of multiyear
electric and gas rate moratoriums, effective July 1, 2006, UE filed requests
with the MoPSC in July 2006 for an electric rate increase of $361
million and for a natural gas delivery rate increase of $11 million.
In March
2007, a stipulation and agreement was approved by the MoPSC authorizing
an
increase in annual natural gas delivery revenues of $6 million, effective
April
1, 2007. As part of this stipulation and agreement, UE agreed not to
file a
natural gas delivery rate case before March 15, 2010. This agreement
does not
prevent UE from filing to recover infrastructure costs through a statutory
infrastructure system replacement surcharge (ISRS) during this three-year
rate
moratorium. The return on equity to be used by UE for purposes of any
future
ISRS tariff filing is 10.0%.
In
May 2007, the MoPSC issued an
order authorizing a $43 million increase in UE’s base rates for electric service
based on a return on equity of 10.2%. The MoPSC denied UE’s and other
intervenors’ applications for rehearing with respect to certain aspects of the
MoPSC rate order. In July 2007, UE appealed certain aspects of the MoPSC
decision, principally the 10.2% return on equity granted by the MoPSC,
to the
Circuit Court of Cole County in Jefferson City, Missouri. The Office
of Public
Counsel and the Missouri attorney general, who were both intervenors
in the
electric rate case, also appealed certain aspects of the MoPSC decision
to the
Circuit Court of Cole County. We cannot predict the outcome of these
appeals of
the MoPSC rate order. Any change in electric or gas rates may not directly
correspond to a change in UE’s earnings.
In
addition, the MoPSC has initiated a rulemaking
process to develop reliability rules applicable to Missouri investor-owned
utilities that address three focus areas: vegetation management,
infrastructure inspection, and reliability. The MoPSC's proposed
vegetation management and infrastructure inspection rules were published
in the
Missouri Register in July 2007, and a public hearing on these rules is
scheduled
for August 15, 2007. The MoPSC's proposed reliability rules have not yet
been published in the Missouri Register. The ultimate cost of the rules is
subject to their final terms, but could be material.
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,
2007
|
600
|
$ |
50.88
|
-
|
-
|
|||||||||||
May
1 – May 31,
2007
|
-
|
-
|
-
|
-
|
||||||||||||
June
1 – June 30,
2007
|
-
|
-
|
-
|
-
|
||||||||||||
Total
|
600
|
$ |
50.88
|
-
|
-
|
(a)
|
These
shares of Ameren common stock were purchased by Ameren 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, as amended. Ameren does not have any publicly announced
equity
securities repurchase plans or
programs.
|
None
of
the other registrants purchased equity securities reportable under
Item 703 of
Regulation S-K during the April 1 to June 30, 2007 period.
86
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS.
Ameren
At
Ameren’s annual meeting of
shareholders held on April 24, 2007, the following matters were presented
to the
meeting for a vote and the results of such voting are as follows:
Item
(1)
|
Election
of 12 directors (comprising Ameren’s full Board of Directors) to serve
until the next annual meeting of shareholders in
2008.
|
Name
|
For
|
Withheld
|
Broker
Non-Votes(a)
|
Stephen
F. Brauer
|
172,744,706
|
3,380,682
|
-
|
Susan
S. Elliott
|
172,623,835
|
3,501,553
|
-
|
Gayle
P. W. Jackson
|
172,735,245
|
3,390,143
|
-
|
James
C. Johnson
|
172,735,312
|
3,390,076
|
-
|
Richard
A. Liddy
|
172,062,753
|
4,062,635
|
-
|
Gordon
R. Lohman
|
172,404,949
|
3,720,439
|
-
|
Charles
W. Mueller
|
172,537,140
|
3,588,248
|
-
|
Douglas
R. Oberhelman
|
171,969,174
|
4,156,214
|
-
|
Gary
L. Rainwater
|
172,095,957
|
4,029,431
|
-
|
Harvey
Saligman
|
172,438,721
|
3,686,667
|
-
|
Patrick
T. Stokes
|
172,621,903
|
3,503,485
|
-
|
Jack
D. Woodard
|
172,727,233
|
3,398,155
|
-
|
(a)
|
Broker
shares included in the quorum but not voting on the
item.
|
Item
(2)
|
Ameren
proposal regarding ratification of the appointment of
PricewaterhouseCoopers LLP as Ameren’s independent registered public
accountants for the fiscal year ending December 31,
2007.
|
For
|
Against
|
Abstain
|
Broker
Non-Votes(a)
|
173,027,701
|
1,298,461
|
1,799,226
|
-
|
(a)
|
Broker
shares included in the quorum but not voting on the
item.
|
Item
(3)
|
Shareholder
proposal requesting a report on releases from UE’s Callaway nuclear
plant.
|
For
|
Against
|
Abstain
|
Broker
Non-Votes(a)
|
10,401,287
|
106,900,549
|
12,280,634
|
46,542,918
|
(a)
|
Broker
shares included in the quorum but not voting on the
item.
|
UE
At
UE’s
annual meeting of shareholders held on April 24, 2007, the following
individuals
(comprising UE’s full Board of Directors) were elected to serve until the next
annual meeting of shareholders in 2008: Warner L. Baxter, Daniel F. Cole,
Richard J. Mark, Steven R. Sullivan and Thomas R. Voss. 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 April 24, 2007, the following
individuals
(comprising CIPS’ full Board of Directors) were elected to serve until the next
annual meeting of shareholders in 2008: Warner L. Baxter, Scott A. Cisel,
Daniel
F. Cole, Steven R. Sullivan and Thomas R. Voss. Each individual received
25,452,373 votes for election and no withheld votes or broker
non-votes.
CILCO
At
CILCO’s annual meeting of shareholders held on April 24, 2007, the following
individuals (comprising CILCO’s full Board of Directors) were elected to serve
until the next annual meeting of shareholders in 2008: Warner L. Baxter,
Scott
A. Cisel, Daniel F. Cole, Steven R. Sullivan and Thomas R. Voss. Each
individual received 13,563,871 votes for election and no withheld votes
or
broker non-votes.
87
At
IP’s
annual meeting of shareholders held on April 24, 2007, 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, Steven R. Sullivan and Thomas R. Voss. 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.
The
documents listed below are being filed or have previously been filed
on behalf
of the Ameren Companies and are incorporated herein by reference from
the
documents indicated and made a part hereof. Exhibits not identified as
previously filed are filed herewith.
Exhibit
Designation
|
Registrant(s)
|
Nature
of Exhibit
|
Previously
Filed as Exhibit to:
|
Instruments
Defining Rights of Securities Holders, Including
Indentures
|
|||
4.1
|
Ameren
UE
|
UE
Company Order dated June 15, 2007,
establishing
the 6.40% Senior Secured Notes
due
2017 (including the global note)
|
June
15, 2007 Form 8-K, Exhibits
4.2
and 4.3, File No. 1-2967
|
4.2
|
Ameren
UE
|
Supplemental
Indenture dated June 1, 2007
by
and between UE and The Bank of New
York,
as Trustee under the Indenture of
Mortgage
and Deed of Trust dated June 15,
1937,
as amended, relating to the First
Mortgage
Bonds, Senior Notes Series KK
securing
the 6.40% Senior Notes due 2017
|
June
15, 2007 Form 8-K, Exhibit
4.5,
File No. 1-2967
|
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
|
88
Exhibit
Designation
|
Registrant(s)
|
Nature
of Exhibit
|
Previously
Filed as Exhibit to:
|
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
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Executive Officer of UE
|
|
31.4
|
UE
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Financial Officer of UE
|
|
31.5
|
CIPS
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Executive Officer of CIPS
|
|
31.6
|
CIPS
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Financial Officer of CIPS
|
|
31.7
|
Genco
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Executive Officer of Genco
|
|
31.8
|
Genco
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Financial Officer of Genco
|
|
31.9
|
CILCORP
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Executive Officer of CILCORP
|
|
31.10
|
CILCORP
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Financial Officer of CILCORP
|
|
31.11
|
CILCO
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Executive Officer of CILCO
|
|
31.12
|
CILCO
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Financial Officer of CILCO
|
|
31.13
|
IP
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Executive Officer of IP
|
|
31.14
|
IP
|
Rule
13a-14(a)/15d-14(a) Certification of
Principal
Financial Officer of IP
|
|
Section
1350 Certifications
|
|||
32.1
|
Ameren
|
Section
1350 Certification of Principal
Executive
Officer and Principal Financial
Officer
of Ameren
|
|
32.2
|
UE
|
Section
1350 Certification of Principal
Executive
Officer
and Principal Financial
Officer
of UE
|
|
32.3
|
CIPS
|
Section
1350 Certification of Principal
Executive
Officer and Principal Financial
Officer
of CIPS
|
|
32.4
|
Genco
|
Section
1350 Certification of Principal
Executive
Officer and Principal Financial
Officer
of Genco
|
|
32.5
|
CILCORP
|
Section
1350 Certification of Principal
Executive
Officer and Principal Financial
Officer
of CILCORP
|
|
32.6
|
CILCO
|
Section
1350 Certification of Principal
Executive
Officer and Principal Financial
Officer
of CILCO
|
|
32.7
|
IP
|
Section
1350 Certification of Principal
Executive
Officer and Principal Financial
Officer
of IP
|
89
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
Principal
Accounting Officer
(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)
90
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, 2007
91