Item 1. BUSINESS

GENERAL

Ameren, formed in 1997 and headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries.

Below is a summary description of Ameren’s principal subsidiaries, which includes Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

•	Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.

•	Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.

•	ATXI operates a FERC rate-regulated electric transmission business. ATXI is constructing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and operates the Spoon River project, which was placed in service in February 2018. Ameren also evaluates competitive electric transmission investment opportunities as they arise.

The following table presents our total employees at December 31, 2018:

Ameren Missouri	3,798
Ameren Illinois	3,458
Ameren Services	1,582
Ameren	8,838

Labor unions at Ameren’s subsidiaries consist of the International Brotherhood of Electrical Workers, the International Union of Operating Engineers, the Laborer’s International Union of North America, the United Association of Plumbers and Pipefitters, and the United Government Security Officers of America. At December 31, 2018, these labor unions collectively represented about 51% of Ameren’s total employees. They represented 61% and 57% of the employees at Ameren Missouri and Ameren Illinois, respectively. The collective bargaining agreements expire between 2019 and 2021.

For additional information about the development of our businesses, our business operations, and factors affecting our results of operations, financial position, and liquidity, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

BUSINESS SEGMENTS

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI.

Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.

An illustration of the Ameren Companies’ reporting structures is provided below.

(a)	The Ameren Transmission segment also includes allocated Ameren (parent) interest charges, Ameren Transmission Company, LLC, ATX East, LLC, and ATX Southwest, LLC.

RATES AND REGULATION

Rates

The rates that Ameren Missouri, Ameren Illinois, and ATXI are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to customers are determined by governmental entities, including the MoPSC, the ICC, and the FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the prudency of expenditures, the quality of service, regulatory staff knowledge and experience, customer intervention, and economic conditions, as well as social and political views. Decisions made by these governmental entities regarding rates are largely outside of our control. These decisions, as well as the regulatory lag involved in the process of getting new rates approved, could have a material adverse effect on the results of operations, financial position, and liquidity of the Ameren Companies. The extent of the regulatory lag varies for each of Ameren’s electric and natural gas jurisdictions, with the Ameren Transmission and Ameren Illinois Electric Distribution businesses experiencing the least amount of regulatory lag. Depending on the jurisdiction, the effects of regulatory lag are mitigated by various means, including the use of a future test year, the use of trackers and riders, the level and timing of expenditures, annual revenue requirement reconciliations, the decoupling of revenues from sales volumes, and the recovery of certain capital investments under PISA, the RESRAM, and the QIP rider.

The MoPSC regulates rates and other matters for Ameren Missouri. The ICC regulates rates and other matters for Ameren Illinois. The MoPSC and the ICC regulate non-rate utility matters for ATXI. ATXI does not have retail distribution customers; therefore, the MoPSC and the ICC do not have authority to regulate ATXI’s rates. The FERC regulates Ameren Missouri’s, Ameren Illinois’, and ATXI’s cost-based rates for the wholesale transmission and distribution of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.

The following table summarizes the key terms of the rate orders in effect for customer billings for each of Ameren’s rate-regulated utilities as of January 1, 2019:

	Rate Regulator	Allowed Return on Equity	Percent of Common Equity	Rate Base (in billions)	Portion of Ameren’s 2018 Operating Revenues(a)
Ameren Missouri
Electric service(b)	MoPSC	9.2% – 9.7%(c)	(c)	(c)	54%
Natural gas delivery service	MoPSC	(d)	(d)	(d)	2%
Ameren Illinois
Electric distribution delivery service(e)	ICC	8.69%	50.0%	$3.0	25%
Natural gas delivery service(f)	ICC	9.87%	50.0%	$1.6	13%
Electric transmission service(g)	FERC	10.82%	52.0%	$1.9	3%
ATXI
Electric transmission service(g)	FERC	10.82%	56.1%	$1.3	3%

(a)	Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and natural gas purchased for resale for natural gas delivery service, and intercompany eliminations.

(b)	Ameren Missouri’s electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate.

(c)	Based on the MoPSC’s March 2017 rate order. This rate order specified that an implicit return on equity was within a range of 9.2% to 9.7%. The rate order did not specify a percent of common equity or rate base. The return on equity used for allowance for equity funds used during construction is 9.53%.

(d)	Based on the MoPSC’s January 2011 rate order. This rate order did not specify the allowed return on equity, the percent of common equity, or rate base.

(e)

Based on the ICC’s November 2018 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The November 2018 rate order was based on 2017 recoverable costs, expected net plant additions for 2018, and the annual average of the monthly yields during 2017 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ 2019 electric distribution delivery service revenues will be based on its 2019 actual recoverable costs, rate base, common equity percentage, and return on common equity, as calculated under the IEIMA’s performance-based formula ratemaking framework.

(f)	Based on the ICC’s November 2018 rate order. The rate order was based on a 2019 future test year.

(g)

Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking based on each year’s forecasted information. The 10.82% return, which includes a 50 basis points incentive adder for participation in an RTO, could be lowered as a result of a FERC complaint proceeding filed in February 2015 that challenged the allowed return on common equity for MISO transmission owners and will require customer refunds if the FERC approves a return on equity lower than that previously collected through rates. The return on equity applicable to investments in ATXI’s Mark Twain project includes an additional 50 basis points incentive adder related to the unique nature of risks involved in completing the project.

Ameren Missouri

Ameren Missouri’s electric operating revenues are regulated by the MoPSC. Ameren Missouri’s electric service and natural gas distribution service rates are established in a traditional regulatory rate review based on a historical test year and an allowed return on equity. If specific criteria are met, certain of Ameren Missouri’s electric rates may be adjusted without a traditional rate proceeding. For example, Ameren Missouri’s MEEIA customer energy-efficiency program costs, lost electric margins, and any performance incentive are recoverable through a rider that may be adjusted without a traditional rate proceeding, subject to MoPSC prudence reviews. Likewise, the FAC permits Ameren Missouri to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews.

In addition to the MEEIA and the FAC recovery mechanisms, Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a tracker on certain excess deferred taxes, a renewable energy standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and the costs included in customer rates as a regulatory asset or regulatory liability. The difference will be included in base rates in a subsequent MoPSC rate order. Ameren Missouri also employs PISA and the RESRAM, as discussed below.

Under PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Eligible PISA deferrals exclude amounts related to new coal-fired, nuclear, and natural gas generating units and service to new customer premises. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, and all approved PISA deferrals will be added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. PISA mitigates the impacts of regulatory lag between regulatory rate reviews. Costs not included in the PISA deferral, including the remaining 15% of certain property, plant, and equipment not eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions under Missouri Senate Bill 564 apply to Ameren Missouri, including limitations on electric customer rate increases and an electric base rate freeze until April 2020. Customer rates under the MEEIA, the FAC, and the RESRAM riders have not been frozen. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the 2.85% rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review will be subject to the rate cap. Any deferred overages approved for recovery will be recovered in a manner consistent with costs recovered under PISA. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the amount of deferred

overage that would cause customer rates to exceed the 2.85% rate cap. Both the rate increase limitation and PISA are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.

The RESRAM allows Ameren Missouri to mitigate the impacts of regulatory lag for the cost of compliance with renewable energy requirements, including recovery of investments in wind and other renewable generation, and to earn a return on those investments not already provided for in customer rates or any other recovery mechanism by adjusting customer rates on an annual basis without a traditional regulatory rate review. Under the RESRAM, Ameren Missouri is permitted to recover the 15% of renewable generation plant placed in service not recovered under PISA. RESRAM regulatory assets earn carrying costs at short-term interest rates.

Ameren Missouri is a member of MISO, and its transmission rate is calculated in accordance with the MISO Open Access Transmission Tariff. The FERC regulates the rates charged and the terms and conditions for wholesale electric transmission service. The transmission rate update each June is based on Ameren Missouri’s filings with the FERC. This rate is not directly charged to Missouri retail customers because, in Missouri, bundled retail rates include an amount for transmission-related costs and revenues.

Ameren Missouri’s natural gas operating revenues are regulated by the MoPSC. If specific criteria are met, Ameren Missouri’s natural gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas supply costs to be passed directly to customers. The ISRS also permits certain prudently incurred natural gas infrastructure replacement costs to be recovered from customers on a timely basis between regulatory rate reviews. Ameren Missouri is not currently recovering any infrastructure replacement costs under the ISRS. The return on equity for purposes of the ISRS tariff will be determined in the pending natural gas rate review. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information on the pending natural gas rate review.

Ameren Illinois

Ameren Illinois Electric Distribution

Ameren Illinois’ electric distribution delivery service operating revenues are regulated by the ICC. In 2018, Ameren Illinois’ electric distribution delivery service revenues accounted for 88% of Ameren Illinois’ total electric operating revenues.

Ameren Illinois participates in the performance-based formula ratemaking framework established pursuant to the IEIMA, which is available through 2022 unless extended. This framework provides for the recovery of actual costs of electric delivery service that are prudently incurred and the use of the utility’s actual regulated capital structure through a formula for calculating the return on equity component of the cost of capital. A common equity ratio up to and including 50% is considered prudent under the framework. The return on equity component of the formula rate is equal to the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The revenue requirement included in customer rates is reconciled annually with the revenue requirement necessary to reflect the actual costs incurred in a given year, including an allowed return on equity. This annual revenue requirement reconciliation adjustment will be collected from, or refunded to, customers within two years.

Beginning in 2017, the FEJA allowed Ameren Illinois to recover within the following two years its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to 2017, Ameren Illinois’ revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This portion of the law extends beyond the end of formula ratemaking in 2022. Through 2022, revenue differences will be included in the annual formula rate revenue requirement reconciliation. Additionally, this law implemented a customer surcharge, based on zero emission credit purchases, relating to certain nuclear energy centers located in Illinois. The surcharge, like the cost of power purchased by Ameren Illinois on behalf of its customers, is passed through to electric distribution customers with no effect on Ameren Illinois’ earnings.

Ameren Illinois plans to invest approximately $100 million per year in electric energy-efficiency programs through 2023, consistent with targets established by the FEJA. The electric energy-efficiency program investments and the formulaic return on those investments will be collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework.

Ameren Illinois is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed return on equity calculated under the formulas. The performance standards applicable to electric distribution service include improvements in service reliability to reduce both the frequency and duration of outages, a reduction in the number of estimated bills, a reduction of consumption from inactive meters, and a reduction in bad debt expense. The electric distribution service regulatory framework provides for return on equity penalties up to 38 basis points in each year from 2019 through 2022, if these performance standards are not met. Beginning in 2018, the rider for electric energy-efficiency investments provides for increases or decreases of up to 200 basis points to the return on equity. Any adjustments to the return on equity for energy-efficiency investments will depend on annual performance of a historical period relative to energy savings goals. In 2018, there were no performance-related basis point adjustments.

Under the IEIMA, Ameren Illinois is also subject to minimum capital spending levels. Between 2012 and 2021, Ameren Illinois is required to invest a minimum of $625 million in capital projects to modernize its distribution system incremental to its average annual electric distribution service capital projects of $228 million for calendar years 2008 through 2010. Through 2018, Ameren Illinois has invested $592 million in IEIMA capital projects toward its $625 million requirement.

Ameren Illinois employs cost recovery mechanisms for power procurement, renewable energy credits, zero emission credits, and certain environmental costs, as well as bad debt expense and the costs of certain asbestos-related claims not recovered in base rates.

Ameren Illinois Natural Gas

Ameren Illinois’ natural gas operating revenues are regulated by the ICC. In November 2018, the ICC issued a rate order that approved an annual revenue increase of $32 million for Ameren Illinois’ natural gas delivery service, based on a 2019 future test year. If specific criteria are met, Ameren Illinois’ natural gas rates may be adjusted without a traditional rate proceeding, as PGA clauses permit prudently incurred natural gas costs to be passed directly to customers. Ameren Illinois employs a VBA to ensure recoverability of the natural gas distribution service revenue requirement for residential and small nonresidential customers that is dependent on sales volumes. For these rate classes, the VBA allows Ameren Illinois to adjust natural gas distribution service rates without a traditional regulatory rate review when changes occur in sales volumes from normalized sales volumes approved by the ICC in a previous regulatory rate review. Also, Ameren Illinois employs cost recovery mechanisms for customer energy-efficiency program costs, certain environmental costs, and bad debt expenses not recovered in base rates.

Illinois has a law that encourages natural gas utilities to accelerate modernization of the state’s natural gas infrastructure through a QIP rider. Without legislative action, the QIP rider will expire in December 2023. Ameren Illinois’ QIP rider allows a surcharge to be added to customers’ bills to recover depreciation expenses and to earn a return on qualifying natural gas investments that were not previously included in base rates. Eligible natural gas investments include projects to improve safety and reliability and modernization investments, such as smart meters. Recovery begins two months after the qualifying natural gas plant is placed in service and continues until such plant is included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP rider is subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. Upon issuance of a natural gas delivery service rate order, QIP rate base is transferred to base rates and the QIP rider is reset to zero, which mitigates the risk that the QIP rider will exceed its statutory limitations in future years and ensures timely recovery of capital investment.

Ameren Illinois Transmission

Ameren Illinois’ transmission operating revenues are regulated by the FERC. In 2018, Ameren Illinois’ transmission operating revenues accounted for 12% of Ameren Illinois’ electric operating revenues. See Ameren Transmission below for additional information regarding Ameren Illinois’ transmission business.

Ameren Transmission

Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. Both Ameren Illinois and ATXI are members of MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission Tariff. Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated annually and become effective each January with forecasted information. A reconciliation at the end of the year, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates in a subsequent year. Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution, other retail electric suppliers, and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues.

The FERC-allowed return on common equity for MISO transmission owners was challenged by customer groups in two complaint cases filed in November 2013 and February 2015. In September 2016, the FERC issued a final order in the November 2013 complaint case, which became immediately effective, and lowered the allowed base return on common equity to 10.32%, or a 10.82% total allowed return on equity with the inclusion of a 50 basis point adder for participation in an RTO. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case. If approved by the FERC, it would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. It would also require customer refunds, with interest, for that 15-month period. A final FERC order would also establish the allowed return on common equity that will apply prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. In November 2018, the FERC issued an order related to the February 2015 complaint case and the September 2016 final order, which required briefs from the participants to be filed in February 2019 regarding a new methodology for determining the base return on common equity and whether and how to apply the new methodology to the two MISO complaint cases.

Ameren is unable to predict the ultimate impact of the proposed methodology on these complaint cases at this time. As the FERC is under no deadline to issue a final order, the timing of the issuance of the final order in the February 2015 complaint case, or any potential impact to the amounts refunded as a result of the September 2016 final order, is uncertain.

ATXI has three MISO-approved multi-value projects: the Spoon River, Illinois Rivers, and Mark Twain projects. The Spoon River project, which is located in northwest Illinois, was placed in service in February 2018. The Illinois Rivers project involves the construction of a 345-kilovolt line from eastern Missouri across Illinois to western Indiana. Construction of the Illinois Rivers project is substantially complete, with the last section awaiting the outcome of certain legal proceedings, which will delay the expected completion date to 2020. This delay is not expected to materially affect 2019 rate base or earnings. The Mark Twain project is located in northeast Missouri and connects Iowa to the Illinois Rivers project. ATXI plans to complete the Mark Twain project by the end of 2019. As of December 31, 2018, ATXI’s expected remaining investment in both the Illinois Rivers and Mark Twain projects was approximately $150 million, with the total investment in all three projects expected to be more than $1.6 billion.

The FERC has approved transmission rate incentives relating to the three MISO-approved multi-value projects, which allow construction work in progress to be included in rate base, thereby improving the timeliness of cash recovery. Additionally, the Mark Twain project earns an additional 50 basis point return on equity incentive adder, effective as of February 14, 2018, based on the unique nature of risks involved in the project.

For additional information on Ameren Missouri, Ameren Illinois, and ATXI rate matters, including the FERC complaint case challenging the allowed return on common equity for MISO transmission owners, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

General Regulatory Matters

Ameren Missouri, Ameren Illinois, and ATXI must receive FERC approval to enter into various transactions, such as issuing short-term debt securities and conducting certain acquisitions, mergers, and consolidations involving electric utility holding companies. In addition, Ameren Missouri, Ameren Illinois, and ATXI must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities and to conduct mergers, affiliate transactions, and various other activities.

Ameren Missouri, Ameren Illinois, and ATXI are also subject to mandatory reliability standards, including cybersecurity standards adopted by the FERC, to ensure the reliability of the bulk electric power system. These standards are developed and enforced by the NERC, pursuant to authority delegated to it by the FERC. Ameren Missouri, Ameren Illinois, and ATXI are members of the SERC. The SERC is one of eight regional entities representing all or portions of 16 central and southeastern states under authority from the NERC for the purpose of implementing and enforcing reliability standards approved by the FERC. The regional entities of the NERC work to safeguard the reliability of the bulk power systems throughout North America. If any of Ameren Missouri, Ameren Illinois, or ATXI is found not to be in compliance with these mandatory reliability standards, it could incur substantial monetary penalties and other sanctions.

Under the Public Utility Holding Company Act of 2005, the FERC and any state public utility regulatory agency may access books and records of Ameren and its subsidiaries that are found to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries that may affect jurisdictional rates. The act also permits the MoPSC and the ICC to request that the FERC review cost allocations by Ameren Services to other Ameren companies.

Operation of Ameren Missouri’s Callaway energy center is subject to regulation by the NRC. The license for the Callaway energy center expires in 2044. Ameren Missouri’s Osage hydroelectric energy center and Taum Sauk pumped-storage hydroelectric energy center, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other aspects, the general operation and maintenance of the projects. The licenses for the Osage hydroelectric energy center and the Taum Sauk pumped-storage hydroelectric energy center expire in 2047 and 2044, respectively. Ameren Missouri’s Keokuk energy center and its dam in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.

For additional information on regulatory matters, see Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

Environmental Matters

Certain of our operations are subject to federal, state, and local environmental laws, including statutes and regulations, relating to the protection of the safety and health of our personnel, the public, and the environment. These laws include requirements relating to identification, generation, storage, handling, transportation, disposal, recordkeeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials; safety and health standards; and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants, water intake, and the management of waste and byproduct materials.

Failure to comply with these laws could have material adverse effects on us. We could be subject to criminal or civil penalties by regulatory agencies, or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing laws that currently apply to our operations.

The EPA has promulgated environmental regulations that have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, 2018, Ameren Missouri’s fossil fuel-fired energy centers represented 16% and 32% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx, mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Water intake and discharges from power plants are regulated under the Clean Water Act. Such regulation could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, either of which could result in significant capital expenditures. The management and disposal of coal ash is regulated under the CCR rule, which will require the closure of surface impoundments and the installations of dry ash handling systems at several of Ameren Missouri’s energy centers. The individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag. These environmental regulations could also affect the availability of, the cost of, and the demand for power and natural gas that is acquired for Ameren Missouri’s natural gas customers and Ameren Illinois’ electric and natural gas customers. Federal, state, and local authorities continually revise these regulations, which adds uncertainty to our planning process and to the ultimate implementation of these or other new or revised regulations.

For additional discussion of environmental matters, including NOx and SO2 emission reduction requirements, regulation of CO2 emissions, wastewater discharge standards, remediation efforts, CCR management regulations, and a discussion of the EPA’s allegations of violations of the Clean Air Act and Missouri law in connection with projects at Ameren Missouri’s Rush Island energy center, see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

TRANSMISSION

Ameren owns an integrated transmission system that is composed of the transmission assets of Ameren Missouri, Ameren Illinois, and ATXI. Ameren also operates two balancing authority areas: AMMO and AMIL. During 2018, the peak demand was 7,482 megawatts in AMMO and 8,792 megawatts in AMIL. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.

Ameren Missouri, Ameren Illinois, and ATXI are transmission-owning members of MISO. Ameren Missouri is authorized by the MoPSC to participate in MISO through May 2020. Ameren Missouri is required to file a periodic cost-benefit study with the MoPSC in 2020 evaluating Ameren Missouri’s continued participation in MISO.

SUPPLY OF ELECTRIC POWER

Ameren Missouri

Ameren Missouri’s electric supply is primarily generated from its energy centers. Factors that could cause Ameren Missouri to purchase power include, among other things, energy center outages, the fulfillment of renewable energy requirements, the failure of suppliers to meet their power supply obligations, extreme weather conditions, the availability of power at a cost lower than its generation cost, and the absence of sufficient owned generation.

Ameren Missouri files a nonbinding 20-year integrated resource plan with the MoPSC every three years. The most recent integrated resource plan, filed in September 2017, includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable generation by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, adding 100 megawatts of solar generation by 2027, retiring coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs, and adding cost-effective demand response programs.

Ameren Missouri continues to evaluate its longer-term needs for new generating capacity. The need for new energy centers is dependent on several key factors, including continuation of and customer participation in energy-efficiency programs, the amount of distributed generation from customers, load growth, technological advancements, costs of generation alternatives, environmental regulation of coal-fired power plants, and state renewable energy requirements, which could lead to the retirement of current baseload assets before the end of their useful lives or alterations in the way those assets operate. Because of the significant time required to plan, acquire permits for,

and build a baseload energy center, Ameren Missouri continues to study alternatives and to take steps to preserve options to meet future demand. Steps include evaluating the potential for further diversification of Ameren Missouri’s generation portfolio through renewable energy generation, including wind and solar generation, additional customer energy-efficiency and demand response programs, distributed energy resources, and energy storage.

Ameren Illinois

In Illinois, while electric transmission and distribution service rates are regulated, power supply prices are not. Although electric customers are allowed to purchase power from an alternative retail electric supplier, Ameren Illinois is required to be the provider of last resort for its electric distribution customers. In 2018, 2017, and 2016, Ameren Illinois procured power on behalf of its customers for 23% in each year of its total kilowatthour sales. Power purchased by Ameren Illinois for its electric distribution customers who do not elect to purchase their power from an alternative retail electric supplier comes either through procurement processes conducted by the IPA or through markets operated by MISO. The IPA administers an RFP process through which Ameren Illinois procures its expected supply. The power and related procurement costs incurred by Ameren Illinois are passed directly to its electric distribution customers through a cost recovery mechanism. The costs are reflected in Ameren Illinois Electric Distribution’s results of operations, but do not affect Ameren Illinois Electric Distribution’s earnings, because these costs are offset by corresponding revenues. Ameren Illinois charges transmission and distribution service rates to electric distribution customers who purchase electricity from alternative retail electric suppliers, which does affect Ameren Illinois Electric Distribution’s earnings.

Illinois law requires Ameren Illinois to offer rebates for certain net metering customers. It is anticipated that the first rebates will be issued in 2019. The cost of the rebates will be deferred as a regulatory asset, which will earn a return based on the utility’s weighted-average cost of capital. Customers that receive these rebates will be allowed to net their supply service charges, but not their distribution service charges. Beginning in 2017, the FEJA decoupled the electric distribution revenues established in a rate proceeding from the actual sales volumes, which ensures that Ameren Illinois’ electric distribution earnings will not be affected by any changes in sales volumes.

POWER GENERATION

Ameren Missouri owns energy centers that rely on a diverse fuel portfolio, including coal, nuclear, and natural gas, as well as renewable sources of generation, which include hydroelectric, methane gas, and solar. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978. The Callaway nuclear energy center began operation in 1984 and is licensed to operate until 2044. As of December 31, 2018, Ameren Missouri’s fossil fuel-fired energy centers represented 16% and 32% of Ameren’s and Ameren Missouri’s rate base, respectively. See Item 2 – Properties under Part I of this report for information regarding Ameren Missouri’s electric generation energy centers.

Coal

Ameren Missouri has an ongoing need for coal as fuel for generation, and pursues a price-hedging strategy consistent with this requirement. Ameren Missouri has agreements in place to purchase and transport coal to its energy centers. As of December 31, 2018, Ameren Missouri had price-hedged 98% of its expected coal supply and 100% of its coal transportation requirements for generation in 2019. Ameren Missouri has additional coal supply under contract through 2022. The Powder River Basin coal transport agreements that Ameren Missouri has with Union Pacific Railroad and Burlington Northern Santa Fe Railway are currently set to expire at the end of 2024. Ameren Missouri burned approximately 18.0 million tons of coal in 2018.

About 97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Inventories may be adjusted because of generation levels or uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion and maintenance, derailments, and weather. As of December 31, 2018, coal inventories for Ameren Missouri were near targeted levels. Disruptions in coal deliveries could cause Ameren Missouri to pursue a strategy that could include reducing wholesale sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.

Nuclear

The production of nuclear fuel involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, the enrichment of that gas, the conversion of the enriched uranium hexafluoride gas into uranium dioxide fuel pellets, and the fabrication into fuel assemblies. Ameren Missouri has entered into uranium, uranium conversion, uranium enrichment, and fabrication contracts to procure the fuel supply for its Callaway energy center.

The Callaway energy center requires refueling at 18-month intervals. The last refueling was completed in December 2017. The next refueling is scheduled for the spring of 2019. As of December 31, 2018, Ameren Missouri had inventories for all of Callaway’s spring 2019

refueling requirements. Ameren Missouri has inventories and supply contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at least through the 2023 refueling. Ameren Missouri has fuel fabrication service contracts through the 2023 refueling.

RENEWABLE ENERGY CREDITS AND ZERO EMISSION CREDITS

Missouri and Illinois laws require electric utilities to include renewable energy resources in their portfolios. Ameren Missouri and Ameren Illinois satisfied their renewable energy portfolio requirements in 2018.

In Missouri, utilities were required to purchase or generate electricity equal to at least 10% of native load sales from renewable energy sources in 2018. That percentage will increase to at least 15% by 2021, subject to an average 1% annual increase on customer rates over any 10-year period. At least 2% of the annual renewable energy requirement must be derived from solar energy. Ameren Missouri expects to satisfy the nonsolar requirement in 2019 with its Keokuk and Maryland Heights energy centers, a 102-megawatt power purchase agreement with a wind farm operator, and an estimated purchase of approximately $2 million of renewable energy credits in the market. The Keokuk energy center generates electricity using a hydroelectric dam located on the Mississippi River. The Maryland Heights energy center generates electricity by burning methane gas collected from a landfill. Ameren Missouri is meeting the solar energy requirement by purchasing solar-generated renewable energy credits from customer-installed systems and by generating solar energy at its O’Fallon energy center and its headquarters building. In 2018, Ameren Missouri entered into build-transfer agreements to purchase up to 557 megawatts of wind generation. For additional information on these agreements, see Note 2 – Rate and Regulatory Matters under Part II, Item 8 of this report.

Effective June 2017, the FEJA requires the IPA to procure renewable energy credits for all electric distribution customers in Illinois, including those customers supplied by alternative retail electric suppliers. The IPA’s initial long-term renewable resources procurement plan was approved by the ICC in 2018. The IPA’s plan set forth guidelines by which the IPA should procure 15-year contracts for four million wind renewable energy credits per year and four million solar renewable energy credits per year, allocated among Ameren Illinois, Commonwealth Edison Company, and MidAmerican Energy Company based on load. As a result of the allocation, Ameren Illinois is required to purchase 1.2 million wind renewable energy credits per year and 1.2 million solar renewable energy credits per year. The IPA has completed several procurement events, resulting in contractual commitments of 0.9 million wind renewable energy credits per year and 0.9 million solar renewable energy credits per year for Ameren Illinois. The remaining 0.3 million wind renewable and 0.3 million solar energy credits per year for Ameren Illinois will be obtained through IPA procurement events in 2019. Ameren Illinois will execute additional renewable energy credit contracts after these procurements in 2019. The IPA is expected to file its second long-term renewable resources procurement plan in 2019, which, once approved, will establish the 2020 and 2021 renewable energy credit procurement targets.

The FEJA also required Ameren Illinois to enter into contracts for zero emission credits in an amount equal to approximately 16% of the actual amount of electricity delivered to retail customers during calendar year 2014. This one-time zero emission credit procurement by the IPA, approval by the ICC, and execution of zero emission credit contracts were all completed in 2018. Contracts are for 10 years with quantities allocated among Ameren Illinois, Commonwealth Edison Company, and MidAmerican Energy Company. Both renewable energy credits and zero emission credits have cost recovery tariff mechanisms which fully recover or refund the variance between actual costs incurred from the resulting contracts and the amounts collected from customers.

ENERGY EFFICIENCY

Ameren Missouri and Ameren Illinois have implemented energy-efficiency programs to educate and to help their customers become more efficient energy consumers. In Missouri, the MEEIA established a regulatory recovery mechanism that, among other things, allows electric utilities to recover costs with respect to MoPSC-approved customer energy-efficiency programs. The law requires the MoPSC to ensure that a utility’s financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy-efficiency programs. Missouri does not have a law mandating energy-efficiency programs.

In February 2016, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2016 plan. That plan included a portfolio of customer energy-efficiency programs, along with a regulatory recovery mechanism. The MoPSC’s order included a performance incentive that provides for additional revenues if certain MEEIA 2016 customer energy-efficiency goals are achieved, including $27 million if 100% of the goals are achieved during the three-year period. Ameren Missouri must achieve at least 25% of its energy efficiency-goals to be eligible for a MEEIA 2016 performance incentive and can earn more if its energy savings exceed those goals. Through 2018, Ameren Missouri invested $136 million in MEEIA 2016 customer energy-efficiency programs and recognized $11 million in additional revenue related to performance incentives.

In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65

million per year through 2021. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100% of the goals are achieved during the period ended December 2021. Additional revenues may be earned if Ameren Missouri exceeds 100% of its energy savings goals.

Both the MEEIA 2016 and MEEIA 2019 plans include the continued use of the MEEIA rider. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any difference between actual program costs, lost electric margins, and any performance incentive and the amounts collected from customers, without a traditional rate proceeding until lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates, based upon both forecasted program costs and lost electric margins and collected via the MEEIA rider, are reconciled annually to actual results.

State law requires Ameren Illinois to offer customer energy-efficiency programs. In September 2017, the ICC issued an order approving Ameren Illinois’ electric and natural gas energy-efficiency plans, as well as regulatory recovery mechanisms. The order authorized electric and natural gas energy-efficiency program expenditures of $394 million and $62 million, respectively, for the 2018 through 2021 period. Additionally, as part of its IEIMA capital project investments, Ameren Illinois has invested approximately $380 million in smart-grid infrastructure since 2012, including smart meters that enable customers to improve their energy efficiency, and expects to spend another $60 million by 2021.

Historically, Ameren Illinois recovered the cost of its energy-efficiency programs as they were incurred. The FEJA allows Ameren Illinois to earn a return on its electric energy-efficiency program investments made since June 2017. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the company’s weighted-average cost of capital, with the equity return based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. Ameren Illinois plans to invest approximately $100 million per year in electric energy-efficiency programs through 2023, consistent with targets established by the FEJA. The ICC can lower the electric energy-efficiency saving goals if sufficient cost-effective measures are not available. The electric energy-efficiency program investments and the return on those investments will be recovered through a rider; they will not be included in the IEIMA formula rate process.

NATURAL GAS SUPPLY FOR DISTRIBUTION

Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their customers. Ameren Missouri and Ameren Illinois each develop and manage a portfolio of natural gas supply resources. These resources include firm natural gas supply agreements with producers, firm interstate and intrastate transportation capacity, firm no-notice storage capacity leased from interstate pipelines, and on-system storage facilities to maintain natural gas deliveries to customers throughout the year and especially during peak demand periods. Ameren Missouri and Ameren Illinois primarily use Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, Mississippi River Transmission Corporation, Northern Border Pipeline Company, and Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to transactions requiring physical delivery, certain financial instruments, including those entered into in the NYMEX futures market and in the over-the-counter financial markets, are used to hedge the price paid for natural gas. Natural gas supply costs are passed on to customers of Ameren Missouri and Ameren Illinois under PGA clauses, subject to prudence reviews by the MoPSC and the ICC. As of December 31, 2018, Ameren Missouri and Ameren Illinois had price-hedged 62% and 76%, respectively, of their expected 2019 natural gas supply requirements.

For additional information on our fuel, purchased power, and natural gas for distribution supply, see Results of Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Commodity Price Risk under Part II, Item 7A, of this report. Also see Note 1 – Summary of Significant Accounting Policies, Note 7 – Derivative Financial Instruments, Note 13 – Related-party Transactions, and Note 14 – Commitments and Contingencies under Part II, Item 8 of this report.

INDUSTRY ISSUES

We are facing issues common to the electric and natural gas utility industry. These issues include:

•	political, regulatory, and customer resistance to higher rates;

•	the potential for changes in laws, regulations, enforcement efforts, and policies at the state and federal levels;

•	corporate tax law changes, as well as additional interpretations, regulations, amendments, or technical corrections that affect the amount and timing of income tax payments, reduce or limit the ability to claim certain deductions and use carryforward tax benefits, or result in rate base reductions;

•	cybersecurity risks, including the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the theft or inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information;

•	the potential for more intense competition in generation, supply, and distribution, including new technologies and their declining costs;

•	the impact and effectiveness of vegetation management programs;

•	net metering rules and other changes in existing regulatory frameworks and recovery mechanisms to address the allocation of costs to customers who own generation resources that enable them both to sell power to us and to purchase power from us through the use of our transmission and distribution assets;

•	legislation or programs to encourage or mandate energy efficiency and renewable sources of power and the lack of consensus as to who should pay for those programs;

•	pressure on customer growth and usage in light of economic conditions, distributed generation, technological advances, and energy-efficiency initiatives;

•	changes in the structure of the industry as a result of changes in federal and state laws, including the formation and growth of independent transmission entities;

•	changes in the allowed return on common equity on FERC-regulated electric transmission assets;

•	the availability of fuel and fluctuations in fuel prices;

•	the availability of a skilled work force, including retaining the specialized skills of those who are nearing retirement;

•	regulatory lag;

•	the influence of macroeconomic factors on yields of United States Treasury securities and on allowed rates of return on equity provided by regulators;

•	higher levels of infrastructure and technology investments and adjustments to customer rates associated with the TCJA that are expected to result in negative or decreased free cash flow, which is defined as cash flows from operating activities less cash flows from investing activities and dividends paid;

•	public concerns about the siting of new facilities;

•	complex new and proposed environmental laws including statutes, regulations, and requirements, such as air and water quality standards, mercury emissions standards, CCR management requirements, and potential CO2 limitations, which may reduce the frequency at which electric generating units are dispatched based upon their CO2 emissions;

•	public concerns about the potential environmental impacts from the combustion of fossil fuels and some investors’ concerns about investing in energy companies that have fossil fuel-fired generation assets;

•	aging infrastructure and the need to construct new power generation, transmission, and distribution facilities, which have long time frames for completion, with limited long-term ability to predict power and commodity prices and regulatory requirements;

•	public concerns about nuclear generation, decommissioning, and the disposal of nuclear waste; and

•	consolidation of electric and natural gas utility companies.

We are monitoring all these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

OPERATING STATISTICS

The following tables present key electric and natural gas operating statistics for Ameren for the past three years:

Electric Operating Statistics – Year Ended December 31,	2018				2017				2016
Electric Sales – kilowatthours (in millions):
Ameren Missouri:
Residential	14,320				12,653				13,245
Commercial	14,791				14,384				14,712
Industrial	4,499				4,469				4,790
Street lighting and public authority	108				117				125
Ameren Missouri retail load subtotal	33,718				31,623				32,872
Off-system	10,036				10,640				7,125
Ameren Missouri total	43,754				42,263				39,997
Ameren Illinois Electric Distribution(a):
Residential	12,099				10,985				11,512
Commercial	12,717				12,382				12,583
Industrial	11,673				11,436				11,738
Street lighting and public authority	513				515				521
Ameren Illinois Electric Distribution total	37,002				35,318				36,354
Eliminate affiliate sales	(288		)		(440		)		(520		)
Ameren total	80,468				77,141				75,831
Electric Operating Revenues (in millions):
Ameren Missouri:
Residential	$	1,560			$	1,417			$	1,422
Commercial	1,271				1,208				1,224
Industrial	312				305				315
Other, including street lighting and public authority	30			(b)	111				102
Ameren Missouri retail load subtotal	$	3,173			$	3,041			$	3,063
Off-system	278				370				333
Ameren Missouri total	$	3,451			$	3,411			$	3,396
Ameren Illinois Electric Distribution:
Residential	$	867			$	870			$	895
Commercial	511				527				517
Industrial	130				113				96
Other, including street lighting and public authority	39				58				40
Ameren Illinois Electric Distribution total	$	1,547			$	1,568			$	1,548
Ameren Transmission:
Ameren Illinois Transmission(c)	$	267			$	258			$	232
ATXI	166				168				123
Ameren Transmission total	$	433			$	426			$	355
Other and intersegment eliminations	(92		)		(98		)		(103		)
Ameren total	$	5,339			$	5,307			$	5,196

(a)	Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2018, 2017, and 2016, Ameren Illinois procured power on behalf of its customers for 23% of its total kilowatthour sales.

(b)	Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information.

(c)	Includes $53 million, $42 million, and $45 million in 2018, 2017, and 2016, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution.

Electric Operating Statistics – Year Ended December 31,	2018				2017				2016
Ameren Missouri fuel costs (cents per kilowatthour generated)(a)		1.59	¢			1.75	¢			1.79	¢
Source of Ameren Missouri energy supply:
Coal	67.8		%		70.9		%		66.2		%
Nuclear	23.7				19.0				22.8
Hydroelectric	2.5				3.4				3.3
Natural gas	1.0				0.7				0.7
Methane gas and solar	0.1				0.1				0.1
Purchased – Wind	0.6				0.7				0.8
Purchased – Other	4.3				5.2				6.1
Ameren Missouri total	100.0		%		100.0		%		100.0		%

(a) Ameren Missouri fuel costs exclude $44 million, $(35) million, and $5 million, respectively for changes in FAC recoveries.

Natural Gas Operating Statistics – Year Ended December 31,	2018				2017				2016
Natural Gas Sales – dekatherms (in millions):
Ameren Missouri:
Residential	7				6				6
Commercial	4				3				3
Industrial	1				1				1
Transport	9				8				8
Ameren Missouri total	21				18				18
Ameren Illinois Natural Gas:
Residential	60				50				52
Commercial	18				15				17
Industrial	4				3				3
Transport	100				98				94
Ameren Illinois Natural Gas total	182				166				166
Ameren total	203				184				184
Natural Gas Operating Revenues (in millions):
Ameren Missouri:
Residential	$	90			$	77			$	77
Commercial	37				31				30
Industrial	4				4				4
Transport and other	7				14				17
Ameren Missouri total	$	138			$	126			$	128
Ameren Illinois Natural Gas:
Residential	$	581			$	531			$	530
Commercial	159				146				153
Industrial	17				12				10
Transport and other	58				54				61
Ameren Illinois Natural Gas total	$	815			$	743			$	754
Other and intercompany eliminations	(1		)		(2		)		(2		)
Ameren total	$	952			$	867			$	880
Rate Base Statistics – At December 31,	2018				2017				2016
Rate Base (in billions):
Electric and natural gas transmission and distribution	$	11.3			$	10.1			$	9.4
Coal generation	2.0				2.0				2.0
Nuclear and renewables generation	1.8				1.9				1.8
Natural gas generation	0.4				0.4				0.4
Rate base total	$	15.5			$	14.4			$	13.6

AVAILABLE INFORMATION

The Ameren Companies make available free of charge through Ameren’s website (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed with or furnished to the SEC pursuant to Sections 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents, along with eXtensible Business Reporting Language (XBRL) documents, are also available through the SEC’s website (www.sec.gov). Ameren’s website is a channel of distribution for material information about the Ameren Companies. Financial and other material information is routinely posted to, and accessible at, Ameren’s website.

The Ameren Companies also make available free of charge through Ameren’s website the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, finance committee, and nuclear and operations committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures document with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to the Ameren Companies. The information on Ameren’s website, or any other website referenced in this report, is not incorporated by reference into this report.