This document provides an overview of a Midwest Utilities Seminar held in April 2008. It discusses Ameren Corporation, a regional electric and gas utility operating in Missouri and Illinois. The presentation outlines Ameren's business segments and strategy to achieve operational excellence and regulatory frameworks that support earnings growth. Financial projections through 2012 indicate a target of 4-6% annual EPS growth through rate cases and investment in regulated infrastructure. Non-regulated generation is also positioned for potential earnings growth depending on power and fuel prices.

1. Midwest
Utilities
Seminar
April 2008
investing for our future.
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2. Marty Lyons
Senior Vice President & Chief Accounting Officer
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3. Cautionary Statements
All forecasted numbers in this presentation are issued and effective as of January 17, 2008
Regulation G Statement
Ameren has presented certain information in this presentation on a diluted cents per share basis. These diluted per
share amounts reflect certain factors that directly impact Ameren’s total earnings per share. The non-GAAP earnings
per share and non-GAAP earnings per share guidance excludes one or more of the following: costs related to severe
January 2007 storms, abnormal weather, the earnings impact of the settlement agreement among parties in Illinois for
comprehensive electric rate relief and customer assistance, the reversal of accruals made in 2006 for low-income
energy assistance and energy efficiency program funding commitments in Illinois and a March 2007 FERC order, which
retroactively adjusted prior years’ regional transmission organization costs. Ameren believes this information is useful
because it enables readers to better understand the impact of these factors on Ameren’s results of operations and
earnings per share.
In providing non-GAAP earnings guidance and a non-GAAP earnings growth forecast, there could be differences
between non-GAAP earnings and earnings prepared in accordance with Generally Accepted Accounting Principles
(GAAP) for unusual items, such as the 2007 Illinois electric settlement and the impact of abnormal weather. Except for
the Illinois settlement, Ameren is not able to estimate the impact, if any, on future GAAP earnings of these items.
Therefore, Ameren is not able to provide a corresponding GAAP equivalent for its earnings growth rate forecast.
Forward-looking Statements
Ameren’s consolidated and segment earnings guidance excludes one or more of the following: costs related to severe
January 2007 storms, abnormal weather, the earnings impact of the settlement agreement among parties in Illinois for
comprehensive electric rate relief and customer assistance, the reversal of accruals made in 2006 for low-income
energy assistance and energy efficiency program funding commitments in Illinois and a March 2007 FERC order, which
retroactively adjusted prior years’ regional transmission organization costs. Ameren’s earnings guidance assumes
normal weather and is subject to, among other things, regulatory and legislative decisions, plant operations, energy
market and economic conditions, severe storms, unusual or otherwise unexpected gains or losses and other risks and
uncertainties outlined in Ameren’s Forward-looking Statements in its news release issued today and in the Forward-
looking Statements and Risk Factors sections in its periodic filings with the Securities and Exchange Commission.
investing for our future.
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4. Ameren Introduction
● Regional electric and gas utility
• Missouri regulated generation,
transmission and
delivery business CILCO
• Illinois regulated transmission
and delivery businesses
CIPS
UE
• Non-rate-regulated
IP
generation business
● NYSE-listed under AEE
• Market cap. ~ $9 billion
• Component of the S&P 500
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5. Investment Highlights
● Focused on the Basics - the generation of electricity,
and the delivery of electricity and natural gas
● Strong EPS growth prospects
● Strong, sustainable dividend
• Current yield of ~6%
• Focused on future dividend growth
● Commitment to conservative financial management
● Attractive, risk-adjusted long-term total return potential
● Strong underlying value/straight-forward strategy to deliver
shareholder value
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6. Ameren’s Business Plan
● Achieve operational excellence in all Meaningful
aspects of our business investment
in serving
● Improve our customer service, customers
satisfaction and image
● Demonstrate environmental Fair
leadership return High quality
on service
● Improve regulatory frameworks and investment
returns
● Optimize non-rate-regulated High
generation business customer
satisfaction
● Maximize the value of our
shareholders’ investment
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7. Financial Outlook
● Near-term regulatory lag
• Rising cost environment (O&M and capital)
• Fuel
• Reliability projects
• Environmental projects
• Depreciation
• Finance costs
• No significant rate adjustments until late 2008 and early 2009
● Significant longer-term earnings growth opportunities
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8. Fuel Costs
Fuel Costs per MWh(a)
● Fuel costs expected to continue
to increase
● Estimates include all fuel costs $23
$21
$19
(coal, nuclear, natural gas, $17
$15
$14
diesel, emission allowances and
transportation) 2008 2009 2010
● Regulated costs are assumed to Estimated Costs Hedged
be recoverable through a cost
recovery mechanism beginning
in 2009
94% 98%
86%
72%
54%
16%
2008 2009 2010
(a)
Includes contracted and estimated cost increase Regulated Missouri Non-Rate-Regulated
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9. Financial Outlook Opportunities
Regulated Businesses
● Significant longer-term earnings growth
● Regulated rates reflecting more current costs
• Rate cases filed
● Increasing rate base investment
● Earning fair returns in regulated operations
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10. Current Regulated Returns
Support Earnings Growth
● Missouri Regulated Operations(a)
2007 non-GAAP ROE = 9%
Estimated 2008 non-GAAP ROE = 7%
• Allowed return in last rate case was 10.2%. Every 1% equals
approximately $50 million of revenues
● Illinois Regulated Operations(b)
2007 non-GAAP ROE = 5%
Estimated 2008 non-GAAP ROE = 5%
• Allowed return in last rate case was 10%. Every 1% equals
approximately $27 million of revenues
Based on actual and projected financial results excluding non-GAAP items
(a)
Based on actual and projected financial results excluding non-GAAP items and
(b)
impact of goodwill associated with CILCORP and Illinois Power acquisitions
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11. Regulated Investment Plans
Support Earnings Growth
Rate Base Growth
($ in Millions)
$9,000
Missouri
Rate Base $8,000
$7,000
Missouri(a) $6,000
Electric $5,744 $5,000
Gas 218 $4,000
Subtotal $5,962 $3,000
$2,000
$1,000
Illinois(b) $0
Distribution $2,120 2006 2007 2008 2009 2010 2011 2012
$4,500
Transmission 245 Illinois
$4,000
Gas 928 $3,500
Subtotal $3,293 $3,000
$2,500
$2,000
TOTAL $9,255
$1,500
$1,000
(a)
At December 31, 2007 $500
(b)
At December 31, 2006, $0
as submitted in current rate case filings 2006 2007 2008 2009 2010 2011 2012
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12. Illinois Rate Filings
● Illinois electric and gas delivery service rate cases filed November 2,
2007
• Decision by end of September 2008
● Requested revenue increase of $247 million
($180 million electric, $67 million gas)
• 11% ROE; 51% to 53% equity
● Requested rider rate-making mechanisms for electric infrastructure
investment, gas decoupling and bad debt expenses
● ICC staff revenue increase recommendation of $48 million
• One step in a multi-step process
• 10.7% ROE recommended. Modifications to capital structure
• Recommended disallowances include certain A&G costs, plant additions,
storm and post-test year reliability expenditures
• Rider mechanism recommendations
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13. Missouri Rate Case Filing
● Electric rate case filed on April 4, 2008
• Decision by March 2009
● Requested revenue increase of $251 million
• 10.9% ROE; 51% equity; rate base = $5.9 billion
● Increase driven by higher costs and increased investment
• Utilized test year ended March 31, 2008
● Requested implementation of fuel and purchased power
cost recovery mechanism
• Did not pursue environmental cost recovery mechanism
• Expect changes to recently adopted rules to be considered by MoPSC
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14. Financial Outlook Opportunities
Non-rate-regulated Generation
● Position non-rate-regulated business for earnings growth
• Improved plant performance
• Effective marketing, trading and hedging
● EPS contribution expected to be relatively flat through 2010
● Expectations could change meaningfully depending upon future
power, capacity and fuel prices
• Greater prospects for tightening power markets
• Ancillary and capacity market development
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15. Non-rate-regulated Generation
Positioned for Earnings Growth
Baseload Generation Baseload Capacity and
(Megawatthours) Availability Factors
40,000 100%
Net Capacity Factor
Forecasted
35,000 Equivalent Availability Factor
Actual
90%
30,000
25,000
80%
20,000
70%
15,000
10,000
60%
5,000
0 50%
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2007 2008 2009 2010
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16. Solid Market Fundamentals
● Generation hedging policy designed Hedged Power Sales
to reduce risk, but allow for market (excludes capacity-only revenues)
86%
upside Tar
get
● Energy prices 60% Ran
• ATC forward curve for 2008 to 2010 ge
45%
ranged from $48/MWh to $54/MWh
$54
at time of January 17, 2008 $52
$50 MWh
MWh
guidance MWh
• Fundamentals support energy 2008 2009 2010
prices strengthening
Hedged Capacity Sales
● Expect continued development and
tightening of MISO capacity market 28%
• Targeting to sell ~75% 18%
of capacity through 2010 37% 10%
22%
• MISO prices are well below PJM 10%
2008 2009 2010
Embedded in Full Requirements Contract Capacity Only
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17. Financial Objectives
● Targeting 4% to 6% average non-GAAP EPS growth from
normalized 2007 base to 2010
• Driven primarily by regulated business growth
• Goal of ~$4 per share by 2011 and higher in 2012
● Overall percentage of earnings contribution by regulated business
segments forecasted to increase and approximate current annual
dividend by the end of 2010
● Focused on providing a strong, sustainable dividend
• Current yield of ~6%
• Cash flows do not support near-term change
• Focus on future dividend growth
● Targeting long-term total annual shareholder return of ~10%
Bottom line: strong underlying value
Straight-forward strategy to deliver value
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18. Long-Range EPS Expectations
>$4.00
~$3.70
Non-GAAP
Non-GAAP
$3.34
$2.80 - $3.20
Weather-Normalized
$3.24
GAAP
$2.98 GAAP
$2.68 - $3.08
2007 2008 2009 2010 2011 2012
GAAP Non-GAAP
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19. Q&A
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20. Appendix
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21. Ameren Segments
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22. Missouri Regulated
2007 Electric Revenue Mix
● 1.2 million electric and
127,000 gas customers
18%
• Diverse electric revenue mix
44%
● 10,000 MW generation 38%
• Low-cost 7,000 MW baseload
coal-fired and nuclear fleet Residential Commercial Industrial
● 24,000 square miles Average Residential Electricity
• 2,900 miles of electric Prices (2006)
0.19
19¢
transmission lines 0.17
17¢
15¢
0.15
• 32,000 miles of electric
13¢
0.13
distribution lines 11¢
0.11
● 3,300 employees 9¢
0.09
San Francisco
New York City
7¢
Los Angeles
● Residential rates approximately 40% 0.07
Philadelphia
Cleveland
Wash DC
St.Louis*
Houston
Chicago
5¢
Boston
Seattle
Atlanta
Detroit
0.05
Dallas
Miami
below national average 3¢
0.03
Source: Bureau of Labor statistics
Assumes UE’s 2007 rate increase was in effect in 2006
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23. Ameren Illinois Utilities
2007 Margin Mix
● Regulated transmission and
distribution company 29%
Electric
• Owns no generation
Gas
71%
● 1.2 million electric and
830,000 gas customers
● 44,000 square miles
• 4,490 miles of electric transmission lines
• 45,000 miles of electric distribution lines
CILCO
• 17,900 miles of natural gas mains
● 2,300 employees
CIPS
● Current bundled electric rates approximate
IP
national average
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24. Non-Rate-Regulated Generation
● Operate power plants
Edwards
CTGs
• Three legal entities 745 MW
1,140 MW
Coal – 1960
Gas – 2000-01
● Market power and Hutsonville
Duck Creek
related products 150 MW
330 MW
Coal – 1953
Coal – 1976
● 6,300 MW generation
• Low-cost 4,500 MW baseload
coal-fired fleet Coffeen
Meredosia
900 MW
445 MW
● 1,100 employees Coal – 1965
Coal/Oil – 1948
Newton
1,210 MW
Grand Tower CTG
Coal – 1977
510 MW
Gas – 2001
Joppa – 80%
1,000 MW
Coal – 1953
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25. Earnings Guidance
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26. Major 2008 Assumptions
Missouri Regulated Segment
● Electric rate case filed on April 4, 2008
• No impact on 2008 earnings/regulatory lag
● Rising cost environment continues
• Labor, materials, etc.
• Fuel
• Depreciation and financing costs
● Increased investment in rate base and operating expenses to
improve reliability and environmental compliance
● Generation output of 51 million MWh (capacity factor ~83%)
● Callaway nuclear plant refueling in Fall 2008 (25-30 days)
● Normal weather and organic growth
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27. Major 2008 Assumptions
Illinois Regulated Segment
● Electric and gas rate orders effective October 2008
• Requested 11% ROE
• Bad debt expense, electric infrastructure investment and gas decoupling rate
mechanisms approved
● Rising cost environment continues
• Labor, materials, etc.
• Depreciation and financing costs
● Increased investment in rate base and operating expenses to improve
reliability
● Impact of Illinois electric settlement (5 cents per share) excluded from
guidance
● Normal weather and organic growth
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28. Major 2008 Assumptions
Non-Rate-Regulated Generation
● Improved plant operations
• Generation output of 33 million MWh vs. 31 million MWh in 2007
• Generation capacity factor of 79% vs. 74% in 2007
● Hedged approximately 86% of output at December 31, 2007
• Expected realized prices of $53.50/MWh vs. $54.50/MWh in 2007
(including energy and capacity sales)
● Ancillary services market revenues of approximately $15 million
(vs. ~$5 million in 2007)
● Capacity market revenues of approximately $40 million
(vs. ~$25 million in 2007)
● Rising cost environment
• Labor, materials, etc.
• Fuel
• Depreciation and financing costs
● Impact of Illinois electric settlement (7 cents per share)
excluded from guidance
● Illinois Monterey coal mine closure
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29. Major 2008 Assumptions
Corporate
● No new equity issuances planned outside of
DRIP/401k plans (hybrids under consideration)
● Significant levels of debt financings
● No increase in dividend
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30. 2008 Non-GAAP Earnings Guidance
2007 GAAP Earnings per Share Guidance $2.98
2007 Severe storm-related costs 0.09
IL electric rate relief settlement, net 0.21
FERC order – MISO charges 0.06
2007 Non-GAAP Earnings per Share Guidance $3.34
Missouri 2007 rate case (margin and expense) 0.09
Other electric and gas margins 0.69
Weather (estimate) (0.10)
Fuel prices (0.40)
Callaway refueling and maintenance outage 0.06
Plant operations and maintenance (0.19)
Distribution system reliability (0.22)
Other labor and employee benefits (0.06)
Depreciation and amortization (0.03)
Dilution and financing, net (0.06)
Other taxes (0.05)
Other, net (0.07)
2008 Non-GAAP EPS Guidance Range $2.80 – $3.20
Illinois electric rate relief settlement (0.12)
2008 GAAP EPS Guidance Range $2.68 – $3.08
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31. 2008 Non-GAAP Segment Guidance
Contribution to Earnings per Share
2007 2008
Missouri Regulated $1.47 $1.20 – $1.30
Illinois Regulated 0.38 0.35 – 0.45
Non-Rate-Regulated Generation 1.45 1.25 – 1.45
Other 0.04 –
Non-GAAP EPS Guidance Range(a) $3.34 $2.80 – $3.20
(a) The 12 cents per share earnings impact of the settlement agreement among parties in Illinois for comprehensive electric rate relief and customer assistance are
excluded from non-GAAP guidance.
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32. Capital Expenditure Summary
($ in Millions)
Capital Expenditures
● 65% to 70% of total
capital expenditures in the $2,235
regulated business
segments Target Range:
735
● Approximately 70% of $1,600 to $2,100 per year
non-rate-regulated $1,395
generation capital
400
expenditures due to 425 Non-Rate-Regulated Generation
environmental
Illinois Regulated
compliance 310
● Does not include any Missouri Regulated
1030
potential expenditures
Other/Corporate
related to climate 620
legislation
70
40
2007 2008 2009 2010 2011 2012
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33. Expected Cash Flow
($ in Millions)
2008
Funds From Operations $1,340
Capital Expenditures (2,235)
Dividends (530)
EEI Dividends (30)
Free Cash Flow ($1,455)
● Negative free cash flow for foreseeable future, an industry-wide
phenomenon
● Cash flow needs expected to be primarily financed with debt and
proceeds from DRIP/401k plan issuances
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34. 2008 Illinois Electric Rate Redesign
● Illinois electric rate
redesign will result
in quarterly changes 18¢
in earnings per
share, but no annual
change
2¢
7¢
13¢
Q1 Q2 Q3 Q4
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35. Post-2008 Commentary
● Rising cost environment continues (e.g. labor, materials, fuel,
depreciation, financing)
● Regulatory lag will persist, but will be less significant over time
● Rate cases
• Will be more frequent
• Proposed recovery mechanisms will be granted
• Granted fair ROEs
● No Callaway refueling in 2009 and 2012
● New baseload plant decision for Missouri regulated operations
will need to be made
• Constructive regulatory framework will need to be in place
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36. Post-2008 Commentary
● Improved non-rate-regulated generation plant performance
● 2 million MWhs of below-market wholesale contracts at ~$33/MWh
expire in late 2008
● Fundamentals point to more robust energy and capacity prices
compared to current forward curves
● No impact from climate legislation
● No new equity issuances currently planned through 2010, excluding
DRIP/401k plans (hybrids under consideration)
● Focused on strong, sustainable dividend and growing dividend in
the future
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37. Illinois Settlement
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38. Illinois Electric Settlement
● Constructively resolved significant legislative, regulatory and legal
uncertainties
• All major parties participated in settlement
● Provides stability to Illinois electric market and provides agreed path for
power procurement
● Significant disincentives for additional legislative action
• Rate relief programs would terminate
• Financial swap agreements could be terminated or renegotiated
• Strong legal position
● No prohibition on ability to file for delivery service
rate increases
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39. Illinois Electric Settlement Costs
($ in Millions, Except Per Share Amounts)
2007 2008 2009 2010 Total
Ameren Illinois Customers’ Benefit $231.6 $150.4 $100.5 $5.5 $488.0
Contributions of Ameren Companies
Non-rate-regulated Generation 48.2 24.9 15.8 1.0 89.9
Illinois Regulated 30.7 18.0 10.7 0.7 60.1
Total Funding $78.9 $42.9 $26.5 $1.7 $150.0
EPS impact $0.26 $0.12 $0.06 $0.01 $0.45
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40. Illinois Electric Settlement - Swap
● Ameren Illinois utilities entered into swap agreements with an affiliate to lock-in prices
for a portion of power requirements from 2008 through 2012 at relevant market prices
Period Volume Price per MWh
6/1/08 to 12/31/08 400 MW $47.45
1/1/09 to 05/31/09 400 MW $49.47
6/1/09 to 12/31/09 800 MW $49.47
1/1/10 to 5/31/10 800 MW $51.09
6/1/10 to 12/31/10 1,000 MW $51.09
1/1/11 to 12/31/11 1,000 MW $52.06
1/1/12 to 12/31/12 1,000 MW $53.08
● If any of the following events occur, negotiations may be undertaken so as to preserve
the economic benefits of the swap agreements. If unable to negotiate a settlement, the
swap agreements may be terminated in 60 to 90 days after the event occurs
• A state tax is enacted on electric generation
• A state or federal tax is enacted on or regulation is imposed on greenhouse
gas emissions
• A state law is enacted that eliminates retail electric supplier choice for residential
and small commercial customers
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41. Power Procurement
● Procurement for June 2008 to ● New Illinois Power Agency (IPA)
May 2009 is in progress. to procure power for Illinois utilities
Energy & capacity components beginning June 2009
completed • Process based on acquiring
20
standard market products
Contracted Power Supply
18
(e.g., 7x24 and 5x16 blocks
16
of energy)
MWh (in millions)
14
• RFP process with benchmarks
12
• Third party administrator hired
10
8
by IPA
6
• ICC review and approval
4
• Results of IPA procurement
2
process deemed prudent
0
2008 2009 2010 2011 2012
Auction Financial Swap Contracts
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42. References
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43. Ameren Calendar
Illinois
ICC Staff and intervenor rebuttal May 13, 2008
Ameren surrebuttal May 27, 2008
Written prehearing motions May 29, 2008
Evidentiary hearings June 9-13, 2008
Briefs July 2008
Proposed delivery service order August 2008 (estimate)
Final delivery service order issued September 2008
Missouri
Staff and intervenor testimony Aug./Sept. 2008 (estimate)
Hearings December 2008 (estimate)
Electric rate order issued March 2009
Investor Relations
Q1 2008 quiet period Began April 7, 2008
Q1 Earnings release May 2, 2008 (tentative)
Q2 2008 quiet period Begins July 7, 2008
Q3 2008 quiet period Begins October 7, 2008
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44. Major Regulatory Proceedings
Illinois
Web site www.icc.illinois.gov/e-docket
Case # 07-0527
– Interim procurement plan
Case # 07-0585, 07-0586, 07-0587
– Electric delivery services rate cases
Case # 07-0588, 07-0589, 07-0590
– Gas delivery services rate cases
Missouri
Web site www.efis.psc.mo.gov/mpsc/DocketSheet.html
Case # ER-2008-0318
– Electric rate case
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45. Investor Relations Contacts
● Bruce Steinke 314-554-2574
• Vice President & Controller bsteinke@ameren.com
Manager – Investor Relations
● Theresa Nistendirk 314-206-0693
• Managing Supervisor tnistendirk@ameren.com
Investor Relations
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