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Ameren Illinois Co - Quarter Report: 2007 June (Form 10-Q)

ameren10q06302007.htm
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
 
 
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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
     
   
 (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

regulatory and legal certainty, and a viable competitive market in Illinois.

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.

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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

ended June 30, 2007, compared with the same periods in 2006.

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

$2 million and $3 million for the three months and six months ended June 30, 2007, respectively.

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.
 
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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.

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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
 
 
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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.

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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.”
 

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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    
     
 
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

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 from customers through rates.
 
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

IP

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
 

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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)





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               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

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