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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| ☒ | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
for the fiscal year ended December 31, 2019
OR
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(X) | |
| ☐ | AnnualTransition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the fiscal year ended December 31, 2017. |
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| | OR |
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( ) | | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to . |
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Commission File Number | | Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | | IRS Employer Identification No. |
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| 1-14756 | | Ameren Corporation | 43-1723446 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri63103
(314)621-3222
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, Missouri63103
(314)621-3222
43-0559760 |
| | (Missouri Corporation) | | |
| | 1901 Chouteau Avenue | | |
| | St. Louis, Missouri 63103 | | |
| | (314) 621-3222 | | |
| | |
| 1-3672 | | Ameren Illinois Company | | 37-0211380 |
| | (Illinois Corporation) | | |
| | 6 Executive Drive | | |
| | Collinsville, Illinois 62234 | | |
| | (618) 343-8150 | | |
(Illinois Corporation)
10 Executive Drive
Collinsville, Illinois62234
(618)343-8150
Securities Registered Pursuant to Section 12(b) of the Act:
The following security is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:
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Registrant | Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Ameren Corporation | Common Stock, $0.01 par value per share | AEE | New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act:
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| | | |
| Registrant | | Title of each class |
| Union Electric Company |
| Preferred Stock, cumulative, no par value, stated value $100 per share
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| Ameren Illinois Company |
| Preferred Stock, cumulative, $100 par value per share
Depositary Shares, each representing one-fourth1/4 of a share of 6.625%
Preferred Stock, cumulative, $100 par value per share
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Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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| | | | |
| Ameren Corporation | Yes | ý
☒ | No | ¨
☐ |
| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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| | | | |
| Ameren Corporation | Yes | ¨
☐ | No | ý
☒ |
| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
Indicate by checkmark 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.
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| | | | |
| Ameren Corporation | Yes | ý
☒ | No | ¨
☐ |
| Union Electric Company | Yes | ý
☒ | No | ¨
☐ |
| Ameren Illinois Company | Yes | ý
☒ | No | ¨
☐ |
Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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| | | | |
| Ameren Corporation | Yes | ý
☒ | No | ¨
☐ |
| Union Electric Company | Yes | ý
☒ | No | ¨
☐ |
| Ameren Illinois Company | Yes | ý
☒ | No | ¨
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Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
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Ameren Corporation | | ý
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Union Electric Company | | ý
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Ameren Illinois Company | | ý
☐ |
Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| Ameren Corporation | Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ |
| | | Large
Accelerated
Filer
| Smaller reporting company | Accelerated
Filer
| | Non-accelerated
Filer
| | Smaller
Reporting
Company
| ☐ | Emerging Growth Company |
Ameren Corporationgrowth company | | ý | | ¨ | | ¨
| | ¨
| | ¨☐ |
| Union Electric Company | Large accelerated filer | ¨
☐ | Accelerated filer | ☐ | Non-accelerated filer | ☒ |
| | ¨
| Smaller reporting company | ý
☐ | Emerging growth company | ¨ | | ¨☐ |
| Ameren Illinois Company | Large accelerated filer | ¨
☐ | Accelerated filer | ☐ | Non-accelerated filer | ☒ |
| | ¨
| Smaller reporting company | ý
☐ | Emerging growth company | ¨ | | ¨☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
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| Ameren Corporation | ¨ | | | ☐ |
| Union Electric Company | ¨ | | | ☐ |
| Ameren Illinois Company | ¨ | | | ☐ |
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
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| | | | |
| Ameren Corporation | Yes | ¨
☐ | No | ý
☒ |
| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
As of June 30, 2017,28, 2019, the aggregate market value of Ameren Corporation’s common stock, $0.01 par value, (based upon the closing price of the common stock on the New York Stock Exchange on June 30, 2017)28, 2019) held by nonaffiliates was $13,230,607,078.$18,378,774,986. All of the shares of common stock of the other registrants were held by Ameren Corporation as of June 30, 2017.28, 2019.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2018,2020, were as follows:
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| Registrant | Title of each class of common stock | Shares outstanding as of January 31, 2020 |
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| Ameren Corporation | Common stock, $0.01 par value per share: 242,634,798 |
| share | 246,231,712 |
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| Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): 102,123,834 |
| 102,123,834 |
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| Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation (parent company of the registrant): | 25,452,373 |
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company and Ameren Illinois Company for the 20182020 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois Company. Each registrant hereto is filing on its own behalf all of the information contained in this annual 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
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This report contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors under the heading “Forward-looking Statements.” 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.
GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed.
2014 Incentive2017 IRP – Integrated Resource Plan, – The 2014 Omnibus Incentive Compensation Plan, a 20-year nonbinding plan Ameren Missouri filed with the MoPSC in September 2017, which providesincludes Ameren Missouri’s preferred approach for compensatory stock-based awards to eligible employees and directors.meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability.
AER – Ameren Energy Resources Company, LLC, a former Ameren Corporation subsidiary that consisted of non-rate-regulated operations. In December 2013, AER contributed substantially all of its assets and liabilities, including its ownership interests in Ameren Energy Generating Company, Ameren Energy Resources Generating Company, and Ameren Energy Marketing Company, to New AER.
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 – Ameren Corporation, Ameren Missouri, and Ameren Illinois, collectively, which are individual registrants within the Ameren consolidated group.
Ameren Illinois – Ameren Illinois Company, an Ameren Corporation subsidiary that operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois, doing business as Ameren Illinois.
Ameren Illinois Electric Distribution – An Ameren Corporation and Ameren Illinois financial reporting segment consisting of the rate-regulated electric distribution business of Ameren Illinois.
Ameren Illinois Transmission – An Ameren Illinois financial reporting segment consisting of the rate-regulated electric transmission business of Ameren Illinois.
Ameren Illinois Natural Gas – An Ameren Corporation and Ameren Illinois financial reporting segment consisting of the rate-regulated natural gas distribution business of Ameren Illinois.
Ameren Illinois Transmission– An Ameren Illinois Company, an Ameren Corporation subsidiary that operatesfinancial reporting segment consisting of the rate-regulated electric and natural gas transmission and distribution businesses in Illinois, doing business asof Ameren Illinois.
Ameren Missouri – Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri, doing business as Ameren Missouri. Ameren Missouri is also defined as a financial reporting segment of Ameren.
Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services, such as accounting, legal, treasury, and asset management services, to Ameren (parent) and its subsidiaries.
Ameren Transmission – An Ameren Corporation financial reporting segment primarily consisting of the aggregated electric transmission businesses of Ameren Illinois and ATXI.
AMIL – The MISO balancing authority area operated by Ameren, which includes the load of Ameren Illinois and ATXI.
AMMO – The MISO balancing authority area operated by Ameren, which includes the load and energy centers of Ameren Missouri.
ARO – Asset retirement obligations.
ATXI – Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engagedoperates a FERC rate-regulated electric transmission business in the construction and operation of electric transmission assets.MISO.
Baseload – The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
CCR – Coal combustion residuals, which include fly ash, bottom ash, boiler slag, and flue gas desulfurization materials generated from burning coal to generate electricity.
CILCOCCR Rule – Central Illinois Light Company,Coal Combustion Residuals Rule, a former Ameren Corporation subsidiary that was merged with CIPS and IP to form Ameren Illinois.
CIPS – Central Illinois Public Service Company, a predecessor to Ameren Illinois.
Clean Power Plan – “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” an EPA rule which would have established emission guidelines for states to follow in developing plans to reduce CO2 emissions from existing fossil-fuel-fired electric generating units. In October 2017,promulgated by the EPA announced a proposal to repealthat established regulations for the Clean Power Plan.disposal of CCR in landfills and surface impoundments.
CO2 – Carbon dioxide.
COL – Nuclear energy center combined construction and operating license.
Cooling degree-daysdegree days – The summation of positive differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of electricity demand by residential and commercial customers for summer cooling.
Credit Agreements – The Illinois Credit Agreement and the Missouri Credit Agreement, collectively.
CSAPR – Cross-State Air Pollution Rule, an EPA rule that requires states that contribute to air pollution in downwind states to limit air emissions from fossil-fuel-fired electric generating units.
CT – Combustion turbine, used primarily for peaking electric generation capacity.
DCA – Delivery charge adjustment, a rate-adjustment mechanism that decouples natural gas revenues from actual sales volumes for Ameren Missouri’s natural gas business and allows Ameren Missouri to adjust customer rates without a traditional regulatory rate review, subject to MoPSC prudence reviews. The decoupling provisions ensure that Ameren Missouri’s natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions.
Dekatherm – A standard unit of energy equivalent to approximately one million Btus.
DOE – Department of Energy, a United States government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Electric margins – Electric revenues less fuel and purchased power costs.
EMANI – European Mutual Association for Nuclear Insurance.
EPA – Environmental Protection Agency, a United States government agency.
ERISA – Employee Retirement Income Security Act of 1974, as amended.
Excess deferred income taxes – The amountAmounts resulting from the revaluation of deferred income taxes previouslysubject to regulatory ratemaking, which will be collected from, customers that will beor returned to, customers over periodscustomers. Deferred income taxes are revalued when federal or state income tax rates change, and the offset to the revaluation of time determined by our regulators.deferred income taxes subject to regulatory ratemaking is recorded to a regulatory asset or liability.
Exchange Act – Securities Exchange Act of 1934, as amended.
FAC – Fuel adjustment clause, a fuel and purchased power cost recovery mechanism that allows 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 regulatory rate proceeding,review, subject to MoPSC prudence reviews.
FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.
FEJA – Future Energy Jobs Act,a 2016an Illinois law affecting electric distribution utilities. This lawthat allows Ameren Illinois to earn a return on its electric energy-efficiency investments, decouples electric distribution revenues from sales volumes, offers customer rebates for installing distributed generation, and includes extensions and modifications of certain IEIMA performance-based framework provisions, among other things. The decoupling provisions ensure that electric distribution revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions.
FERC – Federal Energy Regulatory Commission, a United States government agency.agency that regulates utility businesses and associated activities of holding and related service companies, including Ameren, Ameren Missouri, Ameren Illinois, ATXI, and Ameren Services.
FTRs – Financial transmission rights, financial instruments that specify whether the holder shall pay or receive compensation for certain congestion-related transmission charges between two designated points.
GAAP – Generally accepted accounting principles in the United States.
Heating degree-daysdegree days – The summation of negative differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter heating by residential and commercial customers.
ICC – Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including Ameren Illinois and ATXI.
IEIMA – Illinois Energy Infrastructure Modernization Act, an Illinois law that established a performance-based formula process for determining electric distribution service rates. By its election to participateThe formula ratemaking process expires in this regulatory framework, Ameren Illinois is required to make incremental capital expenditures to modernize its electric distribution system, to meet performance standards, and to create jobs in Illinois, among other requirements.2022, unless extended.
Illinois Credit Agreement –Ameren’s and Ameren Illinois’ $1.1 billion senior unsecured credit agreement. The agreement which expireswas amended and restated in December 2021,2019 and, unless extended.extended, will expire in December 2024.
IP – Illinois Power Company, a former Ameren Corporation subsidiary that merged with CIPS and CILCO to form Ameren Illinois.
IPA – Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and small commercial customers.
IPH – Illinois Power Holdings, LLC, an indirect wholly owned subsidiary of Dynegy Inc.
IRS – Internal Revenue Service, a United States government agency.
ISRS – Infrastructure system replacement surcharge, a cost recoveryrate-adjustment mechanism that allowsprovides Ameren Missouri to recoverMissouri's natural gas business with recovery of, and a return on, qualifying infrastructure replacement costs from customersinvestments that are placed in service without a traditional regulatory rate proceeding.review, subject to MoPSC prudence reviews.
Kilowatthour – A measure of electricity consumption equivalent to the use of 1,000 watts of power over one hour.
MATS – Mercury and Air Toxics Standards, an EPA rule that limits emissions of mercury and other air toxics from coal- and oil-fired electric generating units.
Medina ValleyMEEIA – AmerenEnergy Medina Valley Cogen, LLC, an Ameren Corporation subsidiary.
MEEIA –A rate-adjustment mechanism allowed under the Missouri Energy Efficiency Investment Act, a Missouri law that allows electric utilities to recover costs related to MoPSC-approved customer energy-efficiency programs.programs without a traditional regulatory rate review, subject to MoPSC prudence reviews.
MEEIA 2013 –Ameren Missouri’s portfolio of customer energy-efficiency programs, net shared benefits,recovery of lost electric margins, and performance incentive for 2013 through 2015, pursuant to the MEEIA,Missouri law, as approved by the MoPSC in August 2012.
MEEIA 2016 –Ameren Missouri’s portfolio of customer energy-efficiency programs, throughput disincentive,recovery of lost electric margins, and performance incentive for March 2016 through February 2019, pursuant to the MEEIA,Missouri law, as approved by the MoPSC in February 2016.
MEEIA 2019 –Ameren Missouri’s portfolio of customer energy-efficiency programs, recovery of lost electric margins, and performance incentive for March 2019 through December 2024, pursuant to Missouri law, as approved by the MoPSC in December 2018.
Megawatthour or MWh – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midcontinent Independent System Operator, Inc., an RTO.
Missouri Credit Agreement –Ameren’s and Ameren Missouri’s $1$1.2 billion senior unsecured credit agreement. The agreement which expireswas amended and restated in December 2021,2019 and, unless extended.extended, will expire in December 2024.
Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.
Mmbtu – One million Btus.
Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.
Moody’s – Moody’s Investors Service, Inc., a credit rating agency.
MoOPC –Missouri Office of Public Counsel.Counsel, a state agency.
MoPSC – Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including Ameren Missouri.
MTM – Mark-to-market.
MW – Megawatt.
Native load – End-use retail customers whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.
Natural gas margins – Natural gas revenues less natural gas purchased for resale.
NAV – Net asset value per share.
NEIL – Nuclear Electric Insurance Limited, which includes all of its affiliated companies.
NERC – North American Electric Reliability Corporation.
Net energy costs – Net energy costs, as defined in the FAC, which include fuel and purchased power costs, including transportation, net of off-system sales.sales and capacity revenues. Substantially all transmission revenues and charges are excluded from net energy costs.
Net shared benefits metering – Ameren Missouri’s share ofNet metering allows customers who generate their own electricity or subscribe to receive output from eligible facilities to feed electricity they do not use back into the present value of lifetimegrid. The customers receive a credit for the energy savings, net of program costs, designedthey add to offset sales volume reductions resulting from MEEIA 2013 customer energy-efficiency programs.the grid.
New AER – New Ameren Energy Resources Company, LLC, a limited liability company formed as a direct wholly owned subsidiary of AER. New AER, acquired by IPH in December 2013, included substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren.
New Madrid Smelter – A former aluminum smelter located in southeast Missouri.
NOx – Nitrogen oxides.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a United States government agency.agency that regulates commercial nuclear power plants and uses of nuclear materials.
NSPS – New Source Performance Standards, provisions under the Clean Air Act.
NSR – New Source Review provisions of the Clean Air Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.
NWPA – Nuclear Waste Policy Act of 1982, as amended.
NYMEX – New York Mercantile Exchange.
NYSE – New York Stock Exchange, Inc.LLC.
OATT – Open Access Transmission Tariff.
OCI – Other comprehensive income (loss) as defined by GAAP.
Off-system sales revenues– Revenues from other than native load sales, including wholesale sales.
OTC – Over-the-counter.
PGA – Purchased Gas Adjustmentgas adjustment tariffs, which permita cost recovery mechanism that permits prudently incurred natural gas costs to be recovered directly from utility customers without a traditional regulatory rate proceeding.review, subject to ICC prudence reviews.
PUHCA 2005PHMSA – Pipeline and Hazardous Materials Safety Administration
PISA – Plant-in-service accounting regulatory mechanism, an election under Missouri law that permits electric utilities to defer and recover 85% of the depreciation expense and a return at the applicable WACC on rate base for certain property, plant, and equipment placed in service after the PISA election date, subject to MoPSC prudence reviews. The Public Utility Holding Company Act of 2005.rate base on which the return is calculated incorporates qualifying capital expenditures since the PISA election date as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes. The regulatory asset for accumulated PISA deferrals earns a return at the applicable WACC. The PISA was elected by Ameren Missouri, effective September 1, 2018.
QIP – Qualifying infrastructure plant. Costsplant, a rate-adjustment mechanism that provides Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure natural gas plant investments that are includedplaced in an Ameren Illinois recovery mechanism.service between regulatory rate reviews, subject to ICC prudence reviews.
Rate base –The basis on which a public utility is permitted to earn an allowed rate of return.a WACC. This basis is the net investment in assets used to provide utility service, which generally consists of in-service property, plant, and equipment, net of accumulated depreciation and accumulated deferred income taxes, inventories, and, depending on jurisdiction, construction work in progress.
Regulatory lag – The exposure to differences in costs incurred and actual sales volume levelsvolumes as compared with the associated amounts included in customer rates. Rate increase requests in traditional regulatory rate reviews can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue increases authorized by regulators will lag behind changing costs and sales volume levelsvolumes when based on historical periods.
RESRAM – Renewable energy standard rate-adjustment mechanism, a rate-adjustment mechanism allowed under Missouri law that enables Ameren Missouri to recover costs relating to compliance with Missouri’s renewable energy standard, including recovery of investments in wind generation and other renewables, and earn a return at the applicable WACC 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, subject to MoPSC prudence reviews. RESRAM regulatory assets will earn carrying costs at short-term interest rates.
Revenue requirement – The cost of providing utility service to customers, which is calculated as the sum of a utility’s recoverable operating expenses, and an alloweda return at the weighted-average cost of capital on rate base, including a return on invested capital, both debt and equity, and an amount for income taxes, based on the currently applicable statutory income tax rates and amortization associated with excess deferred income taxes.
RFP – Request for proposal.
ROE – Return on common equity.
RTO – Regional transmission organization.
S&P – S&P Global Ratings, a credit rating agency.
SEC – Securities and Exchange Commission, a United States government agency.
SERC – SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.
Smart Energy Plan – Ameren Missouri’s plan to upgrade Missouri’s electric grid through at least 2024, which assumes continuation of the PISA. Upgrades include investments to improve reliability and accommodate more renewable energy.
SO2– Sulfur dioxide.
TCJA – The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities; itentities. The TCJA includes specific provisions related to regulated public utilities. Substantially all of the provisions of the TCJA affecting the Ameren Companies, other than certain transition depreciation rules, arewere effective for taxable years beginning after December 31, 2017.
Test year – The selected period of time, typically a 12-month period, for which a utility’s historical or forecasted operating results are used to determine the appropriate revenue requirement.requirement in a regulatory rate review.
Throughput disincentive
TSR –Ameren Missouri’s reduced margin caused by Total shareholder return, the current period’s lower sales volume resulting from MEEIA 2016 customer energy-efficiency programs. Recoverycumulative return of this disincentive is designed to make Ameren Missouri earnings neutral eacha common stock or index over a specified period from the lost margins caused by its MEEIA 2016 customer energy-efficiency programs.of time assuming all dividends are reinvested.
WestinghouseVBA – Westinghouse Electric Company, LLC.
VBA – A volumeVolume balancing adjustment, a rate-adjustment mechanism for Ameren Illinois’ natural gas operations. As a result of this adjustment,business that decouples natural gas revenues from residentialactual sales volumes and small nonresidential customers will increase or decrease as billing determinants differ from filed amounts. This adjustment ensuresallows Ameren Illinois to adjust customer rates without a traditional regulatory rate review, subject to ICC prudence reviews. The decoupling provisions ensure that
Ameren Illinois’ natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions, do not result in an over- or under-collectionfor residential and small nonresidential customers.
WACC – Weighted-average cost of natural gas revenues for these rate classes.capital, which is the weighted-average cost of debt and equity, as allowed by the applicable regulator.
Zero-emissionZero emission credit – A credit that represents the environmental attributes of one MWh of energy produced from certain zero-emissionszero emissions nuclear-powered generation facilities, which certain Illinois utilities are required to purchase pursuant to the FEJA.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” 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 within Risk Factors under Part I, Item 1A, of this report, 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, judicial, or legislative actions, and any changes in regulatory policies and ratemaking determinations, that may change regulatory recovery mechanisms, such as those that may result from a rehearing of the complaint case filed in February 2015 with theNovember 2019 FERC seeking a reduction inorder determining the allowed base return on common equityROE under the MISO tariff, the Notices of Inquiry issued by the FERC in March 2019, Ameren Missouri’s proceedingelectric service regulatory rate review filed with the MoPSC to pass through to customer rates the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA,July 2019, and Ameren Illinois’ natural gas delivery service regulatory rate review filed with the ICC in January 2018, Ameren Illinois’ proceeding filed with the ICC to pass through to its natural gas customer rates the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA, the request filed by MISO participants, including Ameren Illinois and ATXI, with the FERC to allow revisions to 2018 electric transmission rates to reflect the impacts of the reduction in the federal statutory corporate income tax rate enacted under the TCJA, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;February 2020;
the effect and continuation of Ameren Illinois’ participationelection to participate in performance-based formula ratemaking frameworks under the IEIMAfor its electric distribution service and the FEJA,its participation in electric energy-efficiency programs, including the direct relationship between Ameren Illinois’ return on common equityROE and the 30-year United States Treasury bond yields,yields;
the effect on Ameren Missouri of any customer rate caps pursuant to Ameren Missouri’s election to use the PISA, including an extension of use beyond 2023, if requested by Ameren Missouri and approved by the related financial commitments;MoPSC;
the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, and energy policies;
the effects of changes in federal, state, or local tax laws, regulations, interpretations, or rates, including additional regulations, interpretations,as a result of amendments or technical corrections to the TCJA, and any challenges to the tax positions taken by the Ameren Companies;Companies, if any;
the effects on demand for our services resulting from technological advances, including advances in customer energy-efficiencyenergy efficiency, energy storage, and private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;
the effectiveness of Ameren Missouri’s customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA plans;programs;
Ameren Illinois’ ability to achieve the performance standards applicable to its electric distribution business and the FEJA electric customer energy-efficiency goals and the resulting impact on its allowed return on program investments;ROE;
our ability to align overall spending, both operating and capital, with frameworks established by our regulators and to recover these costs in a timely manner in our attempt to earn our allowed returns on equity;ROEs;
the cost and availability of fuel, such as ultra-low-sulfurlow-sulfur coal, natural gas, and enriched uranium, used to produce electricity; the cost and availability of purchased power, zero-emissionzero emission credits, renewable energy credits, and natural gas for distribution; and the level and volatility of future market prices for such commodities and credits, including our ability to recover the costs for such commodities and credits and our customers’ tolerance for any related price increases;
disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from Westinghouse, Callaway energy center’s onlythe one NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;Ameren Missouri’s Callaway Energy Center’s assemblies;
the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy Ameren Missouri’s energy sales;
the effectiveness of our risk management strategies and our use of financial and derivative instruments;
the ability to obtain sufficient insurance, including insurance for Ameren Missouri’s Callawaynuclear and coal-fired energy center,centers, or, in the absence of insurance, the ability to recover uninsured losses from our customers;
the impact of cyberattacks on us or our suppliers, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information;
business and economic conditions, including their impact on interest rates, collection of our receivable balances, and demand for our products;
the effects of the TCJA on us and the resulting treatment by regulators will have on our results of operations, financial position, and liquidity;
disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, including as a result of the implementation of the TCJA, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;
the actions of credit rating agencies and the effects of such actions;
the impactinability of adopting new accounting guidanceour counterparties to meet their obligations with respect to contracts, credit agreements, and the application of appropriate accounting rules and guidance;
financial instruments;
the impact of weather conditions and other natural phenomena on us and our customers, including the impact of system outages;
the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;
the effects of breakdowns or failures of equipment in the operation ofelectric generation, electric and natural gas transmission andor distribution, or natural gas storage facilities systems and storage facilities, such as leaks, explosions, and mechanical problems, and compliance with natural gas safety regulations;equipment, which could result in unanticipated liabilities or unplanned outages;
the effects of our increasing investment in electric transmission projects, as well as potential wind and solar generation projects, our ability to obtain all of the necessary approvals to complete the projects, and the uncertainty as to whether we will achieve our expected returns in a timely manner;
operation of Ameren Missouri’s Callaway energy center,Energy Center, including planned and unplanned outages, and decommissioning costs;
the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
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| • | Ameren Missouri’s ability to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs; |
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| • | the impact of current environmental regulationslaws and new, more stringent, or changing requirements, including those related to NSR, CO2, and the implementation of the Affordable Clean Energy Rule, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our operating costs or investment requirements, result in an impairment of our assets, cause us to sell our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect; |
the impact of complying with renewable energy standards in Missouri and Illinois and with the zero emission standard in Illinois;
Ameren Missouri’s ability to acquire wind and other renewable energy generation facilities and recover its cost of investment and related return in a timely manner, which is affected by the ability to obtain all necessary project approvals; the ability of developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary materials and equipment, among other things; the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind and solar generation technologies; and Ameren Missouri’s ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost for each facility;
the effect of a possible cash or net share settlement of the forward sale agreement relating to common stock in the event of changes to Ameren’s expected cash requirements;
labor disputes, work force reductions, changes in future wage and employee benefits costs, including those resulting from changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;
the impact of negative opinions of us or our utility services that our customers, investors, legislators, or regulators may have or develop, which could result from a variety of factors, including failures in system reliability, failure to implement our investment plans or to protect sensitive customer information, increases in rates, or negative media coverage;coverage, or concerns about environmental, social, and/or governance practices;
the impact of complying with renewable energy portfolio requirements in Missouri and Illinois;
labor disputes, work force reductions, future wage and employee benefits costs, including changes in discount rates, mortality tables, and returns on benefit plan assets;adopting new accounting guidance;
the inabilityeffects of our counterparties to meet their obligations with respect to contracts, credit agreements,strategic initiatives, including mergers, acquisitions, and financial instruments;
the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy Ameren Missouri’s energy sales;divestitures;
legal and administrative proceedings;
the impact of cyber attacks, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information; and
acts of sabotage, war, terrorism, or other intentionally disruptive acts.
New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. 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.
PART I
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 including– Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as the provision ofproviding shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise. 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 developing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and placed the Spoon River project in service in February 2018.
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• | Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri. |
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• | Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois. |
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| • | ATXI operates a FERC rate-regulated electric transmission business in the MISO. |
The following table presents our total employees by function at December 31, 2017:2019:
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| Ameren Missouri: | |
| Electric and natural gas transmission and distribution | 1,716 |
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| Generation | 1,721 |
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| Other support services | 635 |
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| Total Ameren Missouri | 3,6394,072 |
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| Ameren Illinois: | |
| Electric and natural gas transmission and distribution | 2,856 |
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| Other support services | 620 |
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| Total Ameren Illinois | 3,4233,476 |
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| Ameren Services – support services | 1,5531,775 |
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| Total Ameren | 8,6159,323 |
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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, 2017,2019, these labor unions collectively represented about 52%50% of Ameren’s total employees. They represented 62%60% and 57%56% of the employees at Ameren Missouri and Ameren Illinois, respectively. The Ameren Missouri collective bargaining agreementsunit contracts expire between 2018in 2021 and 2020.2022, which cover 3% and 97% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2020, 2021, 2022, and 2023, which cover 1%, 92%, 1%, and 6% of represented employees, respectively.
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 and Note 2 – Rate and Regulatory Matters 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 is primarily composedconsists of the aggregated electric transmission businesses of Ameren Illinois and ATXI.ATXI.
Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.Transmission.
An illustration of the Ameren and Ameren Illinois’Companies’ reporting structures is provided below. For additional information on financial reporting segments, see Note 1 – Summary of Significant Accounting Policies and Note 15 – Segment Information under Part II, Item 8, of this report.
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| (a) | The Ameren Transmission segment also includes associatedallocated 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 annual revenue requirement reconciliations, the decoupling of revenues from sales volumes to ensure revenues approved in a regulatory rate review are not affected by changes in sales volumes, the recovery of certain capital investments between traditional regulatory rate reviews, the level and timing of expenditures, the use of a future test year, and the implementationuse of trackers and riders, the level and timing of expenditures, and regulatory frameworks that include annual revenue requirement reconciliations and decoupling of revenues from sales volumes.riders.
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.
For additional information on Ameren Missouri, Ameren Illinois, and ATXI rate matters, 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.
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, 2018:2020: | | | | Rate Regulator | Allowed
Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren’s 2017 Operating Revenues(a) | Rate Regulator | Effective
Rate Order
Issued In | Allowed
ROE | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren’s 2019 Operating Revenues(a) |
| Ameren Missouri | | |
Electric service(b) | MoPSC | 9.2% - 9.7%(c) | (c) | 54% | MoPSC | March 2017(c) | 9.2% – 9.7%(c) | (c) | 52% |
| Natural gas delivery service | MoPSC | (d) | 2% | MoPSC | August 2019(d) | 9.4% – 9.95%(d) | 52.0% | (d) | 2% |
| Ameren Illinois | | |
Electric distribution delivery service(e) | ICC | 8.40% | 50.0% | $2.7 | 25% | ICC | December 2019 | 8.91% | 50.0% | $3.2 | 25% |
Natural gas delivery service(f) | ICC | 9.60% | 50.0% | $1.2 | 12% | ICC | November 2018 | 9.87% | 50.0% | $1.6 | 14% |
Electric transmission service(g) | FERC | 10.82% | 51.6% | $1.6 | 4% | FERC | (g) | 10.38% | 51.3% | $2.1 | 4% |
| ATXI | | |
Electric transmission service(g) | FERC | 10.82% | 56.2% | $1.3 | 3% | FERC | (g) | 10.38% | 59.3% | $1.4 | 3% |
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| (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. |
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| (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. Ameren Missouri has a pending electric service regulatory rate review it filed with the MoPSC in July 2019. For additional information regarding this regulatory rate review, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. |
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| (c) | Based on the MoPSC’s March 2017 rate order. This rate order specified that an implicit return on equityROE was within a range of 9.2% to 9.7%. TheThis rate order did not specify a percent of common equity or rate base. The return on equityROE used for allowance for equity funds used during construction is 9.53%. |
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| (d) | Based on the MoPSC’s January 2011This rate order.order specified that an implicit ROE was within a range of 9.4% to 9.95%. This rate order did not specify the allowed return on equity, the percent of common equity, or rate base. It includes the impacts on rate base and operating revenues relating to the ISRS for investments after the January 2011 rate order. |
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| (e) | Based on the ICC’s December 2017 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The December 2017This rate order was based on 2016 recoverable2018 actual costs, expected net plant additions for 2017,2019, and the annual average of the monthly yields during 20162018 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ 20182020 electric distribution delivery service revenues will be based on its 20182020 actual recoverable costs, rate base, common equity percentage, and return on common equity,an allowed ROE, as calculated under the IEIMA’s performance-based formula ratemaking framework. |
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| (f) | Based on the ICC’s December 2015 rate order. TheThis rate order was based on a 20162019 future test year. Ameren Illinois has a pending natural gas delivery service regulatory rate review it filed with the ICC in February 2020. For additional information regarding this regulatory rate review, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. |
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| (g) | Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking framework based on each year’s forecasted information. The 10.82%10.38% return, which includes thea 50 basis points incentive adder for participation in an RTO, could be lowered by a FERC complaint proceeding filedis based on the FERC’s November 2019 order. For additional information regarding this order and related requests for rehearing, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. The ROE applicable to investments in February 2015 that challengedATXI’s Mark Twain project includes an additional 50 basis point incentive adder related to the allowed return on common equity for MISO transmission owners and will require customer refunds ifunique nature of risks involved in completing the FERC approves a return on equity lower than that previously collected through rates.project. |
Ameren Missouri
Ameren Missouri’s electric operating revenues are subject to regulation by the MoPSC. If certain criteria are met, Ameren Missouri’s electric rates may be adjusted without a traditional rate proceeding. For example, Ameren Missouri’s MEEIA customer energy-efficiency program costs, net shared benefits or throughput disincentive, 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 FAC and the MEEIA recovery mechanisms, Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, 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 is a member of MISO, and its transmission rate is calculated in accordance with the MISO OATT. 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 subject to regulation by the MoPSC. If certain 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 more timely basis between regulatory rate reviews. Ameren Missouri is not currently recovering any infrastructure replacement costs under the ISRS.
Ameren Illinois
Ameren Illinois Electric Distribution
Ameren Illinois’ electric distribution delivery service operating revenues are regulated by the ICC. In 2017, 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 and the FEJA. The IEIMA 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. The return on equity component of the formula rate is equal to the calendar year average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement included in customer rates for that year, including an allowed return on equity. This annual revenue requirement reconciliation adjustment will be collected from, or refunded to, customers within two years.
The FEJA revised certain portions of the IEIMA, extending the IEIMA formula ratemaking framework through 2022, and clarifying that a common equity ratio up to and including 50% is prudent. 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 the FEJA, 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 the IEIMA in 2022. Through 2022, revenue differences will be included in the annual IEIMA revenue requirement reconciliation. Additionally, this law implemented a customer surcharge 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, will be passed through to electric distribution customers with no effect on Ameren Illinois’ earnings.
Pursuant to the FEJA, and consistent with the energy-efficiency plan for 2018 through 2021 approved by the ICC, Ameren Illinois plans to invest up to $99 million in electric energy-efficiency programs per year. Ameren Illinois plans to make additional investments of a similar level in electric energy-efficiency programs per year that will earn a return through 2030. The electric energy-efficiency program investments and the 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 regulatory framework applicable to electric
distribution service provides for return on equity penalties up to 34 basis points in 2018, and up to 38 basis points in each year from 2019 through 2022, if these performance standards are not met. Beginning in 2018, the regulatory framework applicable to 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.
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. From 2012 through 2017, Ameren Illinois invested $508 million in IEIMA capital projects toward its $625 million requirement.
Ameren Illinois employs cost recovery mechanisms for power procurement, customer energy-efficiency program costs incurred before June 2017, 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 December 2015, the ICC issued a rate order that approved an increase in revenues for Ameren Illinois’ natural gas delivery service, based on a 2016 future test year. The rate order also approved the VBA for residential and small nonresidential customers. In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49 million, which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider, as explained in more detail below. The request was based on a 10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. If certain 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. 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. Recovery begins two months after the natural gas investments are placed in service and continues until the investments are included in base rates in a future natural gas 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 the natural gas rate order, QIP recoveries will be included in base rates and the QIP rider will be 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 2017, Ameren Illinois’ transmission service 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 is primarily composed 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 OATT. 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 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 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 of 12.38% was challenged by customer groups in two complaint cases filed in November 2013 and in February 2015. As a result of a FERC order issued in the November 2013 complaint case, a 10.82% total allowed return on common equity has been reflected in rates since September 2016, inclusive of the 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 September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. The FERC is under no deadline to issue a final order in the February 2015 complaint case.
ATXI has three MISO-approved multi-value projects, the Illinois Rivers, Spoon River, and Mark Twain projects. As of December 31, 2017, ATXI’s expected remaining investment in all three projects was approximately $300 million, with the total investment expected to be more than $1.6 billion. The Illinois Rivers project involves the construction of a 345-kilovolt line from eastern Missouri across Illinois to western Indiana. ATXI has obtained a certificate of public convenience and necessity and project approvals from the ICC and the MoPSC for each state’s portion of the Illinois Rivers project. The last line segment of this project is expected to be completed by the end of 2019; however, delays associated with property acquisition could delay the completion date. As of December 31, 2017, all 10 substations and seven of the nine line segments for Illinois Rivers were complete and in-service. The Spoon River project is located in northwest Illinois. ATXI placed the Spoon River project in service in February 2018. The Mark Twain project is located in northeast Missouri and connects Iowa to the Illinois Rivers project. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to complete the Mark Twain project by the end of 2019.
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.
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 (with maturities of more than 12 months) 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 PUHCAthe Public Utility Holding Company Act of 2005, the FERC and anythe state public utility regulatory agencyagencies in each state Ameren and its subsidiaries operate in 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. PUHCA 2005The 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 centerEnergy Center is subject to regulation by the NRC. The license for the Callaway energy centerEnergy Center expires in 2044. Ameren Missouri’s hydroelectric Osage Energy Center and pumped-storage hydroelectric energy center and Taum Sauk pumped-storage hydroelectric energy center,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 centerEnergy Center and the Taum Sauk pumped-storage hydroelectric energy centerEnergy Center expire in 2047 and 2044, respectively. Ameren Missouri’s Keokuk energy centerEnergy 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 environmental statutes and regulationslaws 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. These environmental regulations could also affect the availability of, the cost of, and the demand for electricity and natural gas sold to Ameren Missouri’s and Ameren Illinois’ customers as well as the demand for off-system sales. 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. Failure to comply with these statutes or regulationslaws could have a material adverse effectseffect 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 statutes and regulationslaws 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, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% 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 revised 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 oflitigation against Ameren Missouri with respect to NSR, the Clean Air Act, and Missouri law in connection with projects at Ameren Missouri’s Rush Island energy center,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 MISO balancing authority areas: AMMO and AMIL. During 2017,The AMMO balancing authority area includes the load and energy centers of Ameren Missouri, and had a peak demand was 7,814of 7,363 megawatts in AMMO2019. The AMIL balancing authority area includes the load of Ameren Illinois, and 8,877had a peak demand of 8,735 megawatts in AMIL.2019. 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 the MISO. Ameren Missouri is authorized by the MoPSC to participate in the MISO through May 2020. The previously2024. Ameren Missouri is periodically required cost-benefit study related to Ameren Missouri’smake a filing with the MoPSC regarding its continued participation in MISO, as required periodically by the MoPSC and originally expected to be filedMISO. The next filing is due in 2017, was deferred upon approval of the MoPSC. Ameren Missouri expects to file the periodic cost-benefit study in 2020, based on the deferral granted by the MoPSC.2023.
Ameren Missouri, Ameren Illinois, and ATXI are members of the SERC. The SERC is responsible for ensuring the reliable operation of the bulk electric power system in all or portions of 16 central and southeastern states. The Ameren Companies, like all owners and operators of the bulk electric power system, are subject to mandatory reliability standards that are promulgated by the NERC and its regional entities, such as the SERC, and are enforced by the FERC.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 portfolio 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 absencethe lack of sufficient owned generation. Additionally, Ameren Missouri may need to fulfill purchased power needs from another source if a supplier is unable to meet its power supply obligations.
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,hydroelectric, and nuclear power. It also includes expanding renewable energy generation by adding at least 700 megawatts of wind generation by 2020 in Missouri, and neighboring states, adding 100 megawatts of solar generation over the next 10 years,by 2027, expanding customer energy-efficiency programs, adding cost-effective demand response programs, and retiring coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs,lives.Ameren Missouri may be adversely affected if the MoPSC does not allow recovery ofthe remaining investment, if any, and adding cost-effective demand response programs.decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. Ameren Missouri expects to file its next integrated resource plan in September 2020.
Ameren Missouri continues to evaluate its longer-term needs for new generating capacity. The need for ainvestment in new sources of energy center is dependent on several key factors, including continuation of and customer participation in energy-efficiency programs, andthe amount of distributed generation from customers, load growth, technological advancements, costs of generation alternatives, environmental regulation of coal-fired power plants, and state renewable portfolio standards,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.operate, which could result in increased capital expenditures and/or increased operations and maintenance expenses. 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.
See also 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.
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 2019, 2018, and 2017, 2016, and 2015, Ameren Illinois procured power on behalf of its customers for 23%22%, 23%, and 26%23%, respectively, 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 the 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.
See Note 13 – Related-party Transactions and Note 14 – Commitments and Contingencies under Part II, Item 8,Illinois law requires Ameren Illinois to offer rebates for certain net metering customers. The cost of this report for additional information on power procurementthe rebates are deferred as a regulatory asset, which earn a return at the applicable WACC. Customers that receive these rebates are allowed to net their supply service charges, but not their distribution service charges. Beginning in Illinois.2017, the FEJA decoupled the electric distribution revenues established in a regulatory rate review from the actual sales volumes, which ensures that Ameren Illinois’ electric distribution revenues are not affected by any changes in sales volumes.
POWER GENERATION
Ameren Missouri owns energy centers that rely on a diverse fuel portfolio, including coal, (Ameren Missouri’s primary fuel source), 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, 2017,2019, Ameren Missouri’s fossil fuel-firedcoal-fired energy centers represented 17%12% and 33%26% 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, 2017,2019, Ameren Missouri had price-hedged 88%100% of its expected coal supply and 99%100% of its coal transportation requirements for generation in 2018.2020. Ameren Missouri has additional coal supply under contract through 2021.2025. 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 2019.2024. Ameren Missouri burned approximately 18.614.3 million tons of coal in 2017.2019.
About 97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming.Wyoming, which has a limited number of suppliers. The remaining coal is typically purchased from the Illinois Basin. InventoriesTargeted coal inventory levels 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, weather, and weather.supplier financial hardship. Coal suppliers in the Power River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations, as well as concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2017,2019, 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.Energy Center.
The Callaway energy centerEnergy Center requires refueling at 18-month intervals. The last refueling was completed in December 2017. May 2019. The next refueling is scheduled for the springfall of 2019. As of December 31, 2017, Ameren Missouri had agreements or inventories to price-hedge all of Callaway’s spring 2019 refueling requirements.2020. Ameren Missouri has inventories, supply contracts, and supplyfuel fabrication service contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at least through the 20222023 refueling. Ameren Missouri has fuel fabrication service contracts through at least 2022.
Natural Gas Supply for GenerationTo maintain deliveries to its natural-gas-fired energy centers throughout the year, especially during the summer peak demand, Ameren Missouri’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. Ameren Missouri primarily uses the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to energy centers. In addition to physical transactions, Ameren Missouri uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
Ameren Missouri’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to its energy centers. This strategy is accomplished by optimizing transportation and storage options and by minimizing cost and price risk through various supply and price-hedging agreements that allow access to multiple natural gas pools, supply basins, and storage services. As of December 31, 2017, Ameren Missouri had price-hedged about 73% of its expected natural gas supply requirements for generation in 2018.
Renewable EnergyRENEWABLE ENERGY AND ZERO EMISSION STANDARDS
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 2019.
In Missouri, utilities arewere required to purchase or generate electricity equal to at least 5%10% of native load sales from renewable energy sources beginning in 2017. That percentage2019, and will be required to purchase or generate at that same threshold in 2020. The requirement will increase to at least 15% byin 2021, subject to an average 1% annual increase on customer rates over any 10-year period. At least 2% of eachthe annual renewable energy portfolio requirement must be derived from solar energy. In 2017, Ameren Missouri met its renewable energy requirements. Ameren Missouri expects to satisfy the nonsolar requirement in 20182020 with its Keokuk energy center and its Maryland Heights energy center, and throughcenters, a 102-megawatt power purchase agreement with a wind farm operator.operator, and an estimated purchase of approximately $1 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 centerEnergy 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 its own solar energy at theits O’Fallon, Lambert, and BJC energy centercenters and at its headquarters building. See SupplyIn May 2019, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 300-megawatt wind generation facility. In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 400-megawatt wind generation facility. Both facilities are expected to be completed by the end of Electric Power above2020 and would support Ameren Missouri’s compliance with the Missouri renewable energy standard. 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 Ameren Illinois to collect funds from all electric distribution customers to fund IPA procurement events for renewable energy credits. In accordance with Illinois law, the amount collected from customers by Ameren Illinois is capped at $1.81 per megawatthour. The IPA establishes its long-term renewable resources procurement plans incorporated in Ameren Missouri’s integrated resourcea filing made every two years. The IPA’s initial long-term renewable resources procurement plan filed withwas approved by the MoPSCICC in September 2017.
State law required2018. The IPA’s plan set forth guidelines by which the IPA should procure 15-year contracts for wind renewable energy resources to equal or exceed 13% of the total electricity that Ameren Illinois supplied to its eligible retail customers for the twelve months ended June 1, 2017. For the 2017 plan year, Ameren Illinois met thecredits and solar renewable energy requirement. Starting June 1, 2017,credits. As a result, 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, through IPA procurement events, which represented approximately 7% of Ameren Illinois’ electric distribution sales in 2019. The IPA has completed several procurement events, resulting in contractual commitments of 0.9 million wind renewable energy credits per year and 1.1 million solar renewable energy credits per year for Ameren Illinois. Ameren Illinois will execute additional renewable energy credit contracts in 2020 and 2021, through IPA procurement events, in order to fulfill its remaining obligations. In February 2020, the ICC approved the IPA’s second long-term renewable resources procurement plan. Under the second plan, based on forecasted customer collections to fund renewable energy credit contracts, the IPA does not anticipate procuring additional contracts. However, if customer funds collected exceed the cost of procured contracts, the IPA may procure additional contracts. Funds collected but not used to procure renewable energy resources for all of its electric distributioncredits will be refunded to customers even if an alternative retail electric supplier provides powerpursuant to the customer. a reconciliation proceeding that would be initiated after August 2021.
The FEJA requiresalso required Ameren Illinois to procure zero-emissionenter 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, pursuant to Illinois’ zero emission standard. This one-time zero emission credit procurement by the IPA, approval by the ICC, and execution of zero emission credit contracts, which expire in 2026, were completed in 2018. Both renewable energy credits and zero emission credits have cost recovery mechanisms, which allow Ameren Illinois to retailcollect from, or refund to, customers in Illinois during calendar year 2014. The zero-emission credit cost recovery mechanism, effective June 1, 2017, fully recovers or refunds, through customer rates,differences between actual costs incurred from the variance in actual zero-emission credit costs incurredresulting contracts and the amounts collected from customers. Ameren Illinois defers the variance as a regulatory asset or liability, respectively. These requirements were, and will continue to be, satisfied through ongoing IPA procurement events.
State law requires Ameren Illinois to offer rebates for certain net metering customers. The cost of the rebates are deferred as a regulatory asset. It will be included in rate base and 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 reduction in sales volumes.Energy EfficiencyCUSTOMER ENERGY-EFFICIENCY PROGRAMS
Ameren Missouri and Ameren Illinois have implemented energy-efficiency programs to educate and to help their customers become more efficient users of energy.energy consumers. In Missouri, the MEEIAMissouri Energy Efficiency Investment Act established a regulatory frameworkrate-adjustment 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 standards.programs.
In February 2016,December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 20162019 plan. ThatThe plan includedincludes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a riderrate-adjustment mechanism. Ameren Missouri intends to collectinvest $226 million over the program costs,life of the throughput disincentive, andplan, including $65 million per year through 2021. In addition, the plan includes a performance incentive from customers. that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals. If the target goals are achieved for 2019, 2020, and 2021, additional
revenues of $7 million, $10 million, and $13 million would be recognized in late 2020, 2021, and 2022, respectively. Incremental additional revenues of up to $1 million, $3 million, and $3 million may be earned for 2019, 2020, and 2021, respectively, and would be recognized in the respective following year, if Ameren Missouri exceeds its targeted energy savings goals. Through 2019, Ameren Missouri has invested $52 million in MEEIA 2019 customer energy-efficiency programs.
The throughput disincentive recovery replacedMEEIA 2019 plan includes the net shared benefits that were collected undercontinued use of the MEEIA 2013 plan.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 throughput disincentiveamounts collected from customers, without a traditional regulatory rate proceedingreview until lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates, based upon both forecasted program costs and throughput disincentive,lost electric margins and collected via the MEEIA rider, are reconciled annually to actual results. Ameren Missouri intends to invest $158 million in MEEIA 2016 customer energy-efficiency programs. In addition, similar to the MEEIA 2013 plan, 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.
State law requires Ameren Illinois to offer customer energy-efficiency programs.programs, and imposes electric energy-efficiency savings goals and a maximum amount of investment in electric energy-efficiency programs through 2030, which is approximately $100 million annually. In September 2017, the ICC issued an order approving Ameren Illinois’ electric and natural gas energy-efficiency plans, as well as mechanisms by which program costs can be recovered from customers.regulatory recovery mechanisms. The order authorized electric and natural gas energy-efficiency program expenditures of $394 million and $62 million, respectively, for the period 2018 through 2021.2021 period. Additionally, as part of its IEIMA capital project investments, Ameren Illinois expects to invest $439has invested $420 million in smart-grid infrastructure fromsince 2012, to 2021, including smart meters that enable customers to improve their energy efficiency.efficiency, and expects to spend another $20 million by 2021.
Historically, Ameren Illinois has recovered the cost of its energy-efficiency programs as they were incurred. Since June 2017, theThe FEJA has allowedallows Ameren Illinois to earn a return on its electric energy-efficiency program investments.investments made since June 2017. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and such investments will earn a return at the company’s weighted-average cost of capital,applicable WACC, with the equity returnROE based on the annual average of the monthly average yieldyields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ returnallowed ROE 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. ThePursuant to the FEJA, also increased the level of electric energy-efficiency saving targets through 2030. Ameren Illinois plans to invest up to $99approximately $100 million per year in electric energy-efficiency programs from 2018 through 2021. Ameren Illinois plans2024, and will earn a return on those investments.While the ICC has approved a plan consistent with this spending level through 2021, the ICC has the ability to make similar yearlyreduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs through 2030. The ICC can lower the electric energy-efficiency saving goals if sufficient cost-effective measures are not available. programs.The electric energy-efficiency program investments and the return on those investments will be recoveredare collected from customers through a rider; they willrider and are not be included in the IEIMAelectric distribution formula rate process.ratemaking framework. Ameren Illinois' natural gas energy efficiency program costs are recovered as they are incurred through a regulatory recovery mechanism.
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 through agreements with producers, firm interstate and intrastate firm 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 NYMEXNew York Mercantile Exchange futures market and in the OTCover-the-counter financial markets, are used to hedge the price paid for natural gas. Natural gas purchasesupply 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, 2017,2019, Ameren Missouri and Ameren Illinois had price-hedged 66%65% and 75%79%, respectively, of their expected 20182020 natural gas supply requirements.
For additional information on our fuel, and 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, and Note 15 – Supplemental Information 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;
changes to corporate income tax law as a result of the enactment of the TCJA,changes, as well as additional interpretations, regulations, amendments, or technical corrections related tothat affect the federalamount and timing of income tax code,payments, reduce or limit the ability to claim certain deductions and any state incomeuse carryforward tax reform;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;
political, regulatory, and customer resistance to higher rates;
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, energy conservation, and renewable sources of power, such as solar, and the lack of consensus as to whohow those programs should pay for those programs;be paid for;
pressure on customer growth and usage in light of economic conditions, distributed generation, energy storage, technological advances, and energy-efficiency or conservation 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;
a further reductionchanges in the allowed return on common equityROE on FERC-regulated electric transmission assets;
the availability of fuel and fluctuations in fuel prices;
the availability of materials and equipment, and the potential disruptions in supply chains resulting from the international public health emergency associated with the novel coronavirus (COVID-19);
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 the allowed rates of return on equityROE 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;
the demand for access to renewable energy generation at rates acceptable to customers;
public concerns about the siting of new facilities;facilities, and challenges that members of the public can assert against applications for governmental permits and other approvals required to site and build new facilities that can result in significant cost increases, delays and denial of the permits and approvals by the regulators;
| |
| • | complex new and proposed environmental laws including statutes, regulations, and requirements, includingsuch 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 somethe use of natural gas;
certain investors’ concerns about investing in energyutility companies that have fossil fuel-firedcoal-fired generation assets;assets and increasing scrutiny of environmental, social, and governance practices;
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, | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 | |
| Electric Sales – kilowatthours (in millions): | | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | | |
| Residential | 12,653 |
| | 13,245 |
| | 12,903 |
| 13,532 |
| | 14,320 |
| | 12,653 |
| |
| Commercial | 14,384 |
| | 14,712 |
| | 14,574 |
| 14,269 |
| | 14,791 |
| | 14,384 |
| |
| Industrial | 4,469 |
| | 4,790 |
| | 8,273 |
| 4,242 |
| | 4,499 |
| | 4,469 |
| |
| Street lighting and public authority | 117 |
| | 125 |
| | 126 |
| 99 |
| | 108 |
| | 117 |
| |
| Ameren Missouri retail load subtotal | 31,623 |
| | 32,872 |
| | 35,876 |
| 32,142 |
| | 33,718 |
| | 31,623 |
| |
| Off-system | 10,640 |
| | 7,125 |
| | 7,380 |
| 5,477 |
| | 10,036 |
| | 10,640 |
| |
| Ameren Missouri total | 42,263 |
| | 39,997 |
| | 43,256 |
| 37,619 |
| | 43,754 |
| | 42,263 |
| |
Ameren Illinois Electric Distribution(a): | | | | | | | | | | | |
| Residential | 10,985 |
| | 11,512 |
| | 11,554 |
| 11,675 |
| | 12,099 |
| | 10,985 |
| |
| Commercial | 12,382 |
| | 12,583 |
| | 12,280 |
| 12,341 |
| | 12,717 |
| | 12,382 |
| |
| Industrial | 11,359 |
| | 11,738 |
| | 11,863 |
| 11,587 |
| | 11,673 |
| | 11,436 |
| |
| Street lighting and public authority | 515 |
| | 521 |
| | 524 |
| 491 |
| | 513 |
| | 515 |
| |
| Ameren Illinois Electric Distribution total | 35,241 |
| | 36,354 |
| | 36,221 |
| 36,094 |
| | 37,002 |
| | 35,318 |
| |
| Eliminate affiliate sales | (440 | ) | | (520 | ) | | (385 | ) | (84 | ) | | (288 | ) | | (440 | ) | |
| Ameren total | 77,064 |
| | 75,831 |
| | 79,092 |
| 73,629 |
| | 80,468 |
| | 77,141 |
| |
| Electric Operating Revenues (in millions): | | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | | |
| Residential | $ | 1,416 |
| | $ | 1,421 |
| | $ | 1,464 |
| $ | 1,403 |
| | $ | 1,560 |
| | $ | 1,417 |
| |
| Commercial | 1,207 |
| | 1,223 |
| | 1,258 |
| 1,157 |
| | 1,271 |
| | 1,208 |
| |
| Industrial | 305 |
| | 315 |
| | 469 |
| 278 |
| | 312 |
| | 305 |
| |
| Other, including street lighting and public authority | 115 |
| | 102 |
| | 84 |
| 127 |
| | 30 |
| (b) | 111 |
| |
| Ameren Missouri retail load subtotal | $ | 3,043 |
| | $ | 3,061 |
| | $ | 3,275 |
| $ | 2,965 |
| | $ | 3,173 |
| | $ | 3,041 |
| |
| Off-system | 370 |
| | 333 |
| | 195 |
| 144 |
| | 278 |
| | 370 |
| |
| Ameren Missouri total | $ | 3,413 |
| | $ | 3,394 |
| | $ | 3,470 |
| $ | 3,109 |
| | $ | 3,451 |
| | $ | 3,411 |
| |
| Ameren Illinois Electric Distribution: | | | | | | | | | | | |
| Residential | $ | 870 |
| | $ | 894 |
| | $ | 858 |
| $ | 848 |
| | $ | 867 |
| | $ | 870 |
| |
| Commercial | 527 |
| | 518 |
| | 474 |
| 497 |
| | 511 |
| | 527 |
| |
| Industrial | 113 |
| | 96 |
| | 124 |
| 127 |
| | 130 |
| | 113 |
| |
| Other, including street lighting and public authority | 58 |
| | 41 |
| | 76 |
| 32 |
| | 39 |
| | 58 |
| |
| Ameren Illinois Electric Distribution total | $ | 1,568 |
| | $ | 1,549 |
| | $ | 1,532 |
| $ | 1,504 |
| | $ | 1,547 |
| | $ | 1,568 |
| |
| Ameren Transmission: | | | | | | | | | | | |
Ameren Illinois Transmission(b)(c) | $ | 258 |
| | $ | 232 |
| | $ | 189 |
| $ | 288 |
| | $ | 267 |
| | $ | 258 |
| |
| ATXI | 168 |
| | 123 |
| | 70 |
| 176 |
| | 166 |
| | 168 |
| |
| Ameren Transmission total | $ | 426 |
| | $ | 355 |
| | $ | 259 |
| $ | 464 |
| | $ | 433 |
| | $ | 426 |
| |
| Other and intersegment eliminations | (97 | ) | | (102 | ) | | (81 | ) | (96 | ) | | (92 | ) | | (98 | ) | |
| Ameren total | $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
| $ | 4,981 |
| | $ | 5,339 |
| | $ | 5,307 |
| |
| |
| (a) | Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2017, 2016,2019, 2018, and 2015,2017, Ameren Illinois procured power on behalf of its customers for 23%22%, 23%, and 26%23%, respectively, 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 $62 million, $53 million, and $42 million $45 million,in 2019, 2018, and $38 million in 2017, 2016, and 2015, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution. |
|
| | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2017 | | 2016 | | 2015 |
| Source of Ameren Missouri energy supply: | | | | | |
| Coal | 70.9 | % | | 66.2 | % | | 67.1 | % |
| Nuclear | 19.0 |
| | 22.8 |
| | 23.3 |
|
| Hydroelectric | 3.4 |
| | 3.3 |
| | 3.6 |
|
| Natural gas | 0.7 |
| | 0.7 |
| | 0.3 |
|
| Methane gas and solar | 0.1 |
| | 0.1 |
| | 0.2 |
|
| Purchased – Wind | 0.7 |
| | 0.8 |
| | 0.7 |
|
| Purchased – Other | 5.2 |
| | 6.1 |
| | 4.8 |
|
| Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % |
|
| | | | | | | | | | | |
Natural Gas Operating Statistics – Year Ended December 31, | 2017 | | 2016 | | 2015 |
| Natural Gas Sales – dekatherms (in millions): | | | | | |
| Ameren Missouri: | | | | | |
| Residential | 6 |
| | 6 |
| | 7 |
|
| Commercial | 3 |
| | 3 |
| | 3 |
|
| Industrial | 1 |
| | 1 |
| | 1 |
|
| Transport | 8 |
| | 8 |
| | 7 |
|
| Ameren Missouri total | 18 |
| | 18 |
| | 18 |
|
| Ameren Illinois Natural Gas: | | | | | |
| Residential | 50 |
| | 52 |
| | 55 |
|
| Commercial | 15 |
| | 17 |
| | 18 |
|
| Industrial | 3 |
| | 3 |
| | 3 |
|
| Transport | 98 |
| | 94 |
| | 89 |
|
| Ameren Illinois Natural Gas total | 166 |
| | 166 |
| | 165 |
|
| Ameren total | 184 |
| | 184 |
| | 183 |
|
| Natural Gas Operating Revenues (in millions): | | | | | |
| Ameren Missouri: | | | | | |
| Residential | $ | 77 |
| | $ | 77 |
| | $ | 84 |
|
| Commercial | 31 |
| | 30 |
| | 34 |
|
| Industrial | 4 |
| | 4 |
| | 5 |
|
| Transport and other | 14 |
| | 17 |
| | 14 |
|
| Ameren Missouri total | $ | 126 |
| | $ | 128 |
| | $ | 137 |
|
| Ameren Illinois Natural Gas: | | | | | |
| Residential | $ | 532 |
| | $ | 531 |
| | $ | 550 |
|
| Commercial | 146 |
| | 153 |
| | 163 |
|
| Industrial | 14 |
| | 12 |
| | 13 |
|
| Transport and other | 51 |
| | 58 |
| | 57 |
|
| Ameren Illinois Natural Gas total | $ | 743 |
| | $ | 754 |
| | $ | 783 |
|
| Other and intercompany eliminations | (2 | ) | | (2 | ) | | (2 | ) |
| Ameren total | $ | 867 |
| | $ | 880 |
| | $ | 918 |
|
| | | | | | |
Rate Base Statistics – At December 31, | 2017 | | 2016 | | 2015 |
| Rate Base (in billions): | | | | | |
| Coal generation | $ | 2.0 |
| | $ | 2.0 |
| | $ | 2.0 |
|
| Natural gas generation | 0.4 |
| | 0.4 |
| | 0.5 |
|
| Nuclear and renewables generation | 1.9 |
| | 1.8 |
| | 1.7 |
|
| Electric and natural gas transmission and distribution | 10.1 |
| | 9.4 |
| | 8.2 |
|
| Rate base total | $ | 14.4 |
| | $ | 13.6 |
| | $ | 12.4 |
|
|
| | | | | | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2019 | | 2018 | | 2017 | |
Ameren Missouri fuel costs (cents per kilowatthour generated)(a) |
| 1.38 | ¢ | |
| 1.59 | ¢ | |
| 1.75 | ¢ | |
| Source of Ameren Missouri energy supply: | | | | | | |
| Coal | 63.4 | % | | 67.8 | % | | 70.9 | % | |
| Nuclear | 23.3 |
| | 23.7 |
| | 19.0 |
| |
| Hydroelectric | 5.0 |
| | 2.5 |
| | 3.4 |
| |
| Natural gas | 0.5 |
| | 1.0 |
| | 0.7 |
| |
| Methane gas and solar | 0.2 |
| | 0.1 |
| | 0.1 |
| |
| Purchased – wind | 0.7 |
| | 0.6 |
| | 0.7 |
| |
| Purchased power | 6.9 |
| | 4.3 |
| | 5.2 |
| |
| Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % | |
(a) Ameren Missouri fuel costs exclude $5 million, $44 million, and $(35) million in 2019, 2018, and 2017, respectively, for changes in FAC recoveries.
|
| | | | | | | | | | | | |
Natural Gas Operating Statistics – Year Ended December 31, | 2019 | | 2018 | | 2017 | |
| Natural Gas Sales – dekatherms (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 7 |
| | 7 |
| | 6 |
| |
| Commercial | 4 |
| | 4 |
| | 3 |
| |
| Industrial | 1 |
| | 1 |
| | 1 |
| |
| Transport | 9 |
| | 9 |
| | 8 |
| |
| Ameren Missouri total | 21 |
| | 21 |
| | 18 |
| |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | 61 |
| | 60 |
| | 50 |
| |
| Commercial | 19 |
| | 18 |
| | 15 |
| |
| Industrial | 4 |
| | 4 |
| | 3 |
| |
| Transport | 101 |
| | 100 |
| | 98 |
| |
| Ameren Illinois Natural Gas total | 185 |
| | 182 |
| | 166 |
| |
| Ameren total | 206 |
| | 203 |
| | 184 |
| |
| Natural Gas Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 81 |
| | $ | 90 |
| | $ | 77 |
| |
| Commercial | 34 |
| | 37 |
| | 31 |
| |
| Industrial | 4 |
| | 4 |
| | 4 |
| |
| Transport and other | 15 |
| | 7 |
| | 14 |
| |
| Ameren Missouri total | $ | 134 |
| | $ | 138 |
| | $ | 126 |
| |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | $ | 570 |
| | $ | 581 |
| | $ | 531 |
| |
| Commercial | 154 |
| | 159 |
| | 146 |
| |
| Industrial | 13 |
| | 17 |
| | 12 |
| |
| Transport and other | 60 |
| | 58 |
| | 54 |
| |
| Ameren Illinois Natural Gas total | $ | 797 |
| | $ | 815 |
| | $ | 743 |
| |
| Other and intercompany eliminations | (2 | ) | | (1 | ) | | (2 | ) | |
| Ameren total | $ | 929 |
| | $ | 952 |
| | $ | 867 |
| |
| |
| |
Rate Base Statistics – At December 31, | 2019 | | 2018 | | 2017 | |
| Rate Base (in billions): | | | | | | |
| Electric and natural gas transmission and distribution | $ | 12.8 |
| | $ | 11.3 |
| | $ | 10.1 |
| |
| Coal generation: | | | | | | |
| Labadie Energy Center | 0.9 |
| | 0.8 |
| | 0.7 |
| |
| Sioux Energy Center | 0.6 |
| | 0.6 |
| | 0.7 |
| |
| Rush Island Energy Center | 0.5 |
| | 0.4 |
| | 0.4 |
| |
| Meramec Energy Center | 0.1 |
| | 0.2 |
| | 0.2 |
| |
| Coal generation total | 2.1 |
| | 2.0 |
| | 2.0 |
| |
| Nuclear generation | 1.4 |
| | 1.3 |
| | 1.5 |
| |
| Renewable generation | 0.5 |
| | 0.5 |
| | 0.4 |
| |
| Natural gas generation | 0.4 |
| | 0.4 |
| | 0.4 |
| |
| Rate base total | $ | 17.2 |
| | $ | 15.5 |
| | $ | 14.4 |
| |
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, eXtensible Business Reporting Language (XBRL) documents, 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 are also available through athe SEC’s website maintained by the SEC (www.sec.gov). Ameren’s own website is oura 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.
Investors should review carefully the following material risk factors and the other information contained in this report. The risks that the Ameren Companies face are not limited to those in this section. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect the results of operations, financial position, and liquidity of the Ameren Companies.
REGULATORY AND LEGISLATIVE RISKS
We are subject to extensive regulation of our businesses, which could adversely affect our results of operations, financial position, and liquidity.businesses.
We are subject to federal, state, and local regulation. ThisThe extensive regulatory framework,frameworks, some of which isare more specifically identified in the following risk factors, regulates,regulate, among other matters, the electric and natural gas utility industries; the rate and cost structure of utilities;utilities, including an allowed ROE; the operation of nuclear power plants; the construction and operation of generation, transmission, and distribution facilities; the acquisition, disposal, depreciation and amortization of assets and facilities; the electric transmission system reliability; and wholesale and retail competition. In the planning and management of our operations, we must address the effects of existing and proposed laws and regulations and potential changes in theour regulatory framework,frameworks, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities. Significant changes in the nature of the regulation of our businesses could require changes to our business planning and management of our businesses and could adversely affect our results of operations, financial position, and liquidity. Failure to obtain adequate rates or regulatory approvals in a timely manner; failure to obtain necessary licenses or permits from regulatory authorities; the impact of new or modified laws, regulations, standards, interpretations, or other legal requirements; or increased compliance costs could adversely affect our results of operations, financial position, and liquidity.
The electric and natural gas rates that we are allowed to charge are determined through regulatory proceedings, which are subject to intervention and appeal. Rates are also subject to legislative actions, which are largely outside of our control. AnyCertain events thatcould prevent us from recovering our costs in a timely manner or from earning adequate returns on our investments could adversely affect our results of operations, financial position, and liquidity.investments.
The rates that we are allowed to charge for our utility services significantly influence our results of operations, financial position, and liquidity. 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. We are exposed to regulatory lag and cost disallowances to varying degrees by jurisdiction, which, if unmitigated, could adversely affect our results of operations, financial position, and liquidity. Rate orders are also subject to appeal, which creates additional uncertainty as to the rates that we will ultimately be allowed to charge for our services. From time to time, our regulators may approve trackers, riders, or other recovery mechanisms that allow electric or natural gas rates to be adjusted without a traditional regulatory rate proceeding.review. These mechanisms could be changed or terminated.
Ameren Missouri’s electric and natural gas utility rates and Ameren Illinois’ natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Ameren Missouri’s rates established in those proceedings are primarily based on
historical costs and revenues. Ameren Illinois’ natural gas rates established in those proceedings are based on estimated future costs and revenues. Thus, the rates that we are allowed to charge for utility services may not match our actual costs at any given time.
Rates include an allowed rate of return on investments established by the regulator, including a return at the applicable WACC on invested capital, both debt and equity,rate base, and an amount for income taxes based on the currently applicable statutory income tax rates and amortization associated with excess deferred income taxes. Although rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital,rate base, there can be no assurance that the regulator will determine that our costs were prudently incurred or that the regulatory process will result in rates that will produce full recovery of such costs or provide for an opportunity to earn a reasonable return on those investments.
With respect to Ameren Missouri’s electricMissouri and natural gasAmeren Illinois, and the utility rates, in years whenindustry generally, have an increased need for cost recovery, primarily driven by capital investments, which is likely to continue in the future. The resulting increase to the revenue requirement needed to recover such costs and operations costs rise or customer usage declines below those levels reflected in rates, we may not be able to earn the alloweda return established by the regulator. Thison investments could result in the deferral or cancellation of planned capital investments, which could reduce themore frequent regulatory rate base investments on which Ameren Missouri earns a rate of return.reviews and requests for cost recovery mechanisms. Additionally, increasing rates could result in regulatory or legislative actions, as well as competitive or political pressures, all of which could adversely affect our results of operations, financial position, and liquidity.
Ameren, through ATXI and Ameren Illinois, is investing significant capital resources in electric transmission. These investments are based on the FERC’s regulatory framework and an allowed ROE that is currently higher than that allowed by our state commissions. However, the FERC regulatory framework and rate of return are subject to change, including as a result of appeals and challenges to the new methodology for determining the base ROE established by the FERC in November 2019. Accordingly, the regulatory framework may be less favorable or the rate of return may be lower in the future, compared with the current regulatory environment and rate of return, all of which may adversely affect Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity. A 50 basis point reduction in the FERC-allowed ROE would reduce Ameren’s and Ameren Illinois’ annual net income by an estimated $10 million and $6 million, respectively, based on each company’s 2020 projected rate base.
As a result of its participation in the performance-based formula ratemaking, framework established pursuant to the IEIMA and the FEJA, Ameren Illinois’ return on equityROE for its electric distribution service and its electric energy-efficiency investments is directly correlated to yields on United States Treasury bonds. Additionally, Ameren Illinois is required to achieve certain performance standards and capital spending levels. Failure to meet these requirements could adversely affect Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity.standards.
Ameren Illinois participateselects to participate in a performance-based formula ratemaking framework established pursuant to the IEIMA for its electric distribution service. BeginningAmeren Illinois’ electric distribution revenues are decoupled from sales volumes, which ensures that the electric distribution revenues authorized in 2017, the FEJA alloweda regulatory rate review are not affected by changes in sales volumes. Ameren Illinois to recover its electric distribution revenue requirement for a given year, independent of actual sales volumes. Since June 2017, the FEJAalso has also allowed Ameren Illinois to earn a return on itsan electric energy-efficiency program rider, which includes a return at the applicable WACC on its program investments whichthat is subject to performance-based formula ratemaking. The ICC annually reviews Ameren Illinois’ rate filings for reasonableness and prudency. If the ICC were to conclude that Ameren Illinois’ costs were not prudently incurred, the ICC would disallow recovery of such costs.
The electric distribution service performance-based formula ratemaking framework expires at the end of 2022, if not extended by the legislature, while the decoupling provisions extend beyond the end of formula ratemaking by law. If not extended, Ameren Illinois would then be required to establish future rates through a traditional regulatory rate review with the ICC, which might result in rates that do not produce a full or timely recovery of costs or provide for an adequate return on equity component under the IEIMAinvestments and the FEJA is equalwould expose Ameren Illinois’ electric distribution business to the calendar yearrisks described in the immediately preceding risk factor.
The allowed ROE under both formula ratemaking recovery mechanisms is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworksROE for both its electric distribution service and its electric energy-efficiency investmentsbusiness is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. With respect to electric distribution service, a 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8$9 million change in Ameren’s and Ameren Illinois’ annual net income, based on its 20182020 projected rate base.
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 equityROE calculated under the ratemaking 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 regulatory framework applicable to electric distribution service regulatory framework provides for return on equityROE penalties up to 34 basis points in 2018, and up to 38 basis points in each year from 20192020 through 2022, if these performance standards are not met. Beginning in 2018, the regulatory framework applicable to electricThe allowed ROE on energy-efficiency investments provides for increasescan be increased or decreases ofdecreased up to 200 basis points, todepending on the return on equity.achievement of annual energy savings goals. Any adjustments to the return on equityallowed ROE for energy-efficiency investments will depend on annual performance of a historical period relative to energy savings goals. In 2019, 2018, and 2017, there were no material performance-related basis point adjustments.
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 2017, Ameren Illinois has invested $508 million in IEIMA capital projects toward its $625 million minimum requirement. If Ameren Illinois does not meet its investment commitments under IEIMA, Ameren Illinois would no longer be eligible to annually update its performance-based formula rates under IEIMA.
Without the extension of formula ratemaking, the IEIMA performance-based formula ratemaking framework expires at the end of 2022. Ameren Illinois would then be required to establish future rates through a traditional rate proceeding with the ICC, which might not result in rates that produce a full or timely recovery of costs or provide for an adequate return on investments. The decoupling provisions of the FEJA do not expire at the end of 2022.
Pursuant to the FEJA, Ameren Illinois plans to invest up to $99approximately $100 million per year in electric energy-efficiency programs from 2018 through 2021 that2024, and will earn a return. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022return on those investments.While the ICC has approved a plan consistent with this spending level through 2030. The2021, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, or ifwhich could reduce the savings goals would require investment levels that exceed amounts allowed by legislation.investments in electric energy-efficiency programs.
As a result of the PISA, Ameren Missouri’s electric rates are subject to a rate cap.
As a result of Ameren Missouri’s election to use the PISA, its rate increases are limited to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in the July 2018 MoPSC order. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the2.85%rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review would be subject to the rate cap. Any deferred overages approved for recovery would be recovered in a manner consistent with costs recovered under the PISA. Increased capital investments and operating costs could cause customer rates to exceed the rate cap. In addition, a decrease in off-system sales, which are included in net energy costs, could also contribute to customer rates exceeding the rate cap. Off-system sales are affected by planned and unplanned outages at Ameren Missouri's energy centers, and by curtailment of generation resulting from unfavorable economic conditions, among other things. 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 the2.85%rate cap. A penalty incurred as the result of exceeding the rate cap could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Both the rate cap and the PISA election are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.
We are subject to various environmental laws and regulations.laws. Significant capital expenditures are required to achieve and to maintain compliance with these laws and regulations.environmental laws. Failure to comply with these laws and regulations could result in the closing of facilities, alterations to the manner in which these facilities operate, increased operating costs, delays and increased costs of building new facilities, or exposure to fines and liabilities, all of which could adversely affect our results of operations, financial position, and liquidity.liabilities.
We are subject to various environmental laws, including statutes and regulations, enforced by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect to environmental laws and regulations.laws. These laws and regulations address emissions, discharges to water, water usage,intake, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. Ameren is also subject to risks from changing or conflicting interpretations of existing laws.
We are also subject to liability under environmental laws that address the remediation of environmental contamination on property currently or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such properties include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws and regulations against us. They could allege injury from exposure to hazardous materials, allege a failure to comply with environmental laws, and regulations, seek to compel remediation of environmental contamination, or seek to recover damages resulting from that contamination.
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, 2017,2019, Ameren Missouri’s fossil fuel-firedcoal-fired energy centers represented 17%12% and 33%26% 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 revised 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 is also subject to risks from changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the power plants implemented modifications. In January 2011, the Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The complaint, as amended in October 2013, allegedMissouri alleging that in performing projects at its coal-fired Rush Island coal-fired energy centerEnergy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling and, in September 2019, entered a final order that required Ameren Missouri to install a flue gas desulfurization system at the projects violated provisionsRush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. There were no fines in the order. In October 2019, Ameren Missouri appealed the district court’s ruling to the United States Court of Appeals for the Eighth Circuit. Additionally, in October 2019, following a request by Ameren Missouri, the district court stayed implementation of the Clean Air Act and Missouri law. Themajority of its order’s requirements while the case then proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. is appealed.The ultimate resolution of this matter could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Among other things and subject to economic and regulatory considerations, resolution of this matter could
result in increased capital expenditures for the installation of air pollution control equipment, as well as increased operations and maintenance expenses.Based upon engineering studies, capital expenditures to comply with the district court’s order for installation of a flue gas desulfurization system at the Rush Island Energy Center are estimated at approximately $1 billion. Further, the flue gas desulfurization system would result in additional operation and maintenance expenses of $30 million to $50 million annually for the life of the energy center. Engineering studies required to develop estimated capital expenditures and estimated additional operation and maintenance expenses for the Labadie Energy Center to comply with the district court’s order will not be undertaken while the case is under appeal.
In 2015,July 2019, the EPA issued the Affordable Clean Power Plan,Energy Rule, which would have establishedestablishes emission guidelines for states to follow in developing plans to limit CO2 emissions standards applicablefrom coal-fired electric generating units. The EPA has identified certain efficiency measures as the best system of emission reduction for coal-fired electric generating units. The Affordable Clean Energy Rule went into effect on September 6, 2019. The rule requires the state of Missouri to existing power plants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In October 2017,develop a compliance plan and submit it to the EPA announcedfor approval by September 2022. The plan is expected to include a proposalstandard of performance for each affected generating unit. We are evaluating the impact of the adoption and implementation of the Affordable Clean Energy Rule and, along with other stakeholders, will be working with the state of Missouri to repealdevelop the Clean Power Plan. In December 2017,compliance plan submitted to the EPA issued an advanced notice of proposed rulemaking to solicit input from stakeholders as to how the EPA should regulate CO2 emissions from existing power plants under the Clean Air Act. Accordingly,EPA. At this time, we no longer expect the Clean Power Plan to take effect. However, the EPA may issue new requirements that would regulate CO2 emissions from existing power plants. We cannot predict the outcome of Missouri’s compliance plan development process. As such, the EPA’s future rulemaking orimpact on the outcome of any legal challenges relating to such future rulemakings, any of which could have an adverse effect on our results of operations, financial position, and liquidity.liquidity of Ameren and Ameren Missouri is uncertain. We also cannot predict the outcome of any potential legal challenges to the rule.
Ameren and Ameren Missouri have incurred and expect to incur significant costs with respect to environmental compliance and site remediation. New or revised environmental regulations, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties or fines, or reduced operations of some of Ameren Missouri’s coal-fired energy centers, which, in turn, could lead to increased liquidity needs and higher financing costs. Actions required to ensure that Ameren Missouri’s facilities and operations are in compliance with environmental laws and regulations could be
prohibitively expensive for Ameren Missouri if the costs are not fully recovered through rates. Environmental laws could require Ameren Missouri to close or to alter significantly the operations of its energy centers. If Ameren Missouri requests recovery of capital expenditures and costs for environmental compliance through rates, the MoPSC could deny recovery of all or a portion of these costs, prevent timely recovery, or make changes to the regulatory framework in an effort to minimize rate volatility and customer rate increases. Capital expenditures and costs to comply with future legislation or regulations might result in Ameren Missouri closing coal-fired energy centers earlier than planned. If these costs are not recoverable through rates, it could lead to an impairment of assets and reduced revenues. Any of the foregoing could have an adverse effect on our results of operations, financial positions, and liquidity.
The TCJA is complex and significantly affects the Ameren Companies. As a result of the TCJA, the Ameren Companies expect lower operating cash flows, driven by lower customer rates, which may need to be funded through debt and/or equity issuances. Further, additional interpretations, regulations, amendments, and technical corrections to the federal income tax code, as well as the associated treatment by our regulators, may adversely affect our results of operations, financial position, and liquidity.
The TCJA, among other things, reduced the federal statutory corporate income tax rate from 35% to 21%Customers’, effective January 1, 2018. Additionally, the TCJA eliminated 50% accelerated depreciation tax benefits for nearly all regulated utility capital investments made after September 27, 2017. As of December 31, 2017, Ameren recorded a noncash charge to earnings of $154 million as a result of the revaluation of deferred taxes, largely attributable to Ameren (parent). Ameren also reclassified deferred income tax liabilities of $2.4 billion to regulatory liabilities. This reclassification is due to the reduction of the federal statutory corporate income tax rate, which reduced such income tax obligations, and the expected return of funds previously collected from customers. Our rate-regulated businesses recover income taxes in customer rates based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds from our customers for income taxes and when we pay such taxes. Excess deferred taxes were created as the deferred income tax obligation decreased due to a reduction in the federal statutory corporate income tax rate.
The elimination of 50% accelerated tax depreciation on nearly all capital investments has caused an increase in Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion). Over the next five years, Ameren may be required to issue incremental debt and/or equity to fund this reduction in operating cash flows, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. Ameren Missouri and Ameren Illinois expect to fund cash flows needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent), with the intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. As a result of the TCJA, financial metrics used by credit rating agencies may be negatively affected, primarily due to expected decreases in operating cash flows discussed above.
Most of the effects of the TCJA will be reflected in adjusted customer electric and gas rates over time. The regulatory treatment of the effects of the TCJA will be subject to the discretion of the FERC, the MoPSC and the ICC. The period over which the return of excess deferred taxes will occur will ultimately be determined by our regulators.
Certain aspects of the TCJA are unclear. These aspects will require interpretations and regulations from the IRS and state taxing authorities, and the TCJA could be subject to potential amendments and technical corrections, any of which could adversely affect our results of operations, financial position, and liquidity. The revaluation of deferred taxes recorded as of December 31, 2017, may be subject to further adjustment in accordance with additional interpretations or as a result of the IRS audit of the 2017 income tax return, either of which could adversely affect our results of operations, financial position, and liquidity. There may be other material adverse effects resulting from the TCJA that we have not yet identified, each of which could be material in any particular quarterly period.
Customers’investors’, legislators’, and regulators’ opinions of us are affected by many factors, including system reliability, implementation of our investment plans, protection of customer information, rates, media coverage, and media coverage. To the extent thatenvironmental, social, and governance practices. Negative opinions developed by customers, investors, legislators, or regulators have or develop a negative opinion of us,could harm our results of operations, financial position, and liquidity could be adversely affected.reputation.
Service interruptions and facility shutdowns can occur due to failures of equipment as a result of severe or destructive weather or other causes. The ability of Ameren Missouri and Ameren Illinois to respond promptly to such failures can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, such as those being undertaken for Ameren Illinois’ electric and natural gas delivery systems, our ability to safeguard sensitive customer information and protect our systems from cyber attacks, and other actions can affect customer satisfaction. The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction. Additionally, negative perceptions or publicity resulting from increasing scrutiny of environmental, social, and governance practices could negatively impact our reputation or investment in our common stock. Customers’, investors’, legislators’, and regulators’ opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation.
If customers, investors, legislators, or regulators have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the returns on common equityROEs we are allowed to earn.earn, as well as the access to, and the cost of, capital. Additionally, negative opinions about us could make it more difficult for our utilities to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volume reductions or increased use of distributed generation by our customers. Any of these consequences could adversely affect our results of operations, financial position, and liquidity.
We are subject to federal regulatory compliance and proceedings, which exposes us tocould result in increasing costs and the potential for regulatory penalties and other sanctions.
TheWe are subject to FERC can impose civil penalties of approximately $1.2 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards.standards required by the NERC. As owners and operators of bulk power transmission systems and electric energy centers, we are subject to mandatory NERC reliability standards, including cybersecurity standards. In addition, our natural gas transmission, distribution, and storage facilities systems are subject to PHMSA rules and regulations. Compliance with these mandatory reliability standards, rules, and regulations may subject us to higher operating costs and may result in increased capital expenditures. We may also incur higher operating costs to comply with potential new regulations issued by these regulatory bodies. If we were found not to be in compliance with these mandatory NERC reliability standards, PHMSA rules and regulations, or FERC regulations, rules, and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations,
financial position, and liquidity. The FERC can impose civil penalties of approximately $1.3 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards. The FERC also conducts audits and reviews of Ameren Missouri’s, Ameren Illinois’, and ATXI’s accounting records to assess the accuracy of its formula ratemaking process, and it can require refunds to customers for previously billed amounts, with interest.
OPERATIONAL RISKS
The construction and acquisition of, and capital improvements to, our electric and natural gas utility infrastructure involve substantial risks. These risks include escalating costs,costs; unsatisfactory performance by the projects when completed,completed; the inability to complete projects as scheduled, which could affect the ability to qualify for some or all of the anticipated federal production or investment tax credits; cost disallowances by regulators,regulators; and the inability to earn an adequate return on invested capital, anycapital. Any of whichthese risks could result in higher costs, andinability to complete anticipated projects, or facility closures.
We expect to incurmake significant capital expenditures to maintain and improve our electric and natural gas utility infrastructure and to comply with existing environmental regulations. We estimate that we will invest up to $11.4$16.6 billion (Ameren Missouri – up to $4.5$8.4 billion; Ameren Illinois – up to $6.6$8.0 billion; ATXI – up to $0.3$0.2 billion) of capital expenditures from 20182020 through 2022. These estimates do not reflect the potential additional investments identified in Ameren Missouri’s integrated resource plan, which could represent incremental investments of approximately $1 billion through 2020 and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made. 2024. These estimates include allowance for equity funds used during construction.construction, but do not include any capital expenditures related to pollution control equipment that may be required as a result of the NSR and Clean Air Act litigation. Investments in Ameren’s rate-regulated operations are expected to be recoverable from customers, but they are subject to prudence reviews and are exposed to regulatory lag of varying degrees by jurisdiction.
Our ability to complete construction projects successfully within projected estimates and to acquire wind generation facilities after they are constructed is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for labor and materials, and labor,including changes to tariffs on materials, reliance on third parties, the ability to obtain required project approvals, and the ability to obtain necessary rights-of-way, easements, and easements. Delaystransmission connections. The schedule, performance, and/or cost, including qualifying for federal production or investment tax credits, of these projects can be affected by many factors. These factors include delays in obtaining permits or regulatory approvals; shortages in materials, equipment, and qualified labor,labor; suppliers and contractors who do not perform as required under their contracts,contracts; changes in the scope and timing of projects,projects; the inability to raise capital on reasonable terms,terms; or other events beyond our control, could affectincluding construction delays due to weather. In February 2020, the developers of the wind generation facilities, to be acquired by Ameren Missouri after construction, received notice from the wind turbine supplier of potential disruptions in its manufacturing, transport, and/or import/export activities resulting from the international public health emergency associated with the novel coronavirus (COVID-19). The developers notified Ameren Missouri that their performance might be delayed as a result. At this time, Ameren Missouri and the developers are unable to estimate the impact to each project, including the project schedule cost, and performancecontracted megawatts. Additionally, we are evaluating the impact of these projects. this international public health emergency on our supply chains.
There is a risk that an energy center might not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such pollution control equipment not be installed on time or not perform as expected, Ameren Missouri could be subject to additional costs and to the loss of its investment in the project or facility.
All of these project and construction risks could adversely affect our results of operations, financial position, and liquidity.
Ameren and Ameren Illinois may not be able to execute their electric transmission investment plans or to realize the expected return on those investments.
Ameren, through ATXI and Ameren Illinois, is investing significant capital resources in electric transmission. These investments are based on the FERC’s regulatory framework and a rate of return on common equity that is currently higher than that allowed by our state commissions. However, the FERC regulatory framework and rate of return are subject to changes, including changes as a result of third-party complaints and challenges at the FERC. The regulatory framework may be less favorable or the rate of return may be lower in the future. A pending complaint case filed with the FERC in February 2015 could reduce the allowed return on common equity and could require customer refunds. A 50 basis point reduction in the FERC-allowed return on common equity would reduce Ameren’s and Ameren Illinois’ earnings by an estimated $8 million and $4 million, respectively, based on each company’s 2018 projected rate base.
A significant portion of Ameren’s electric transmission investments consists of three separate ATXI projects, which have been approved by MISO as multi-value projects. As of December 31, 2017, ATXI’s expected remaining investment in all three projects was approximately $300 million, with the total investment expected to be more than $1.6 billion The last of these projects is expected to be completed in 2019. A failure by ATXI to complete these three projects on time and within projected cost estimates could adversely affect Ameren’s results of operations, financial position, and liquidity.
Within MISO, certain new transmission projects which are eligible for regional cost sharing may be subject to competition. Therefore, Ameren may need to compete to build certain future electric transmission projects in its subsidiaries’ service territories. Such competition could limit Ameren’s future transmission investment.
Our electric generation, transmission, and distribution facilities are subject to operational risks that could adversely affect our results of operations, financial position, and liquidity.risks.
Our financial performance depends on the successful operation of electric generation, transmission, and distribution facilities. Operation of electric generation, transmission, and distribution facilities involves many risks, including:
facility shutdowns due to operator error, or a failure of equipment or processes;
longer-than-anticipated maintenance outages;
failures of equipment that can result in unanticipated liabilities or unplanned outages;
aging infrastructure that may require significant expenditures to operate and maintain;
disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including ultra-low-sulfur coal used by Ameren Missouri to comply with environmental regulations;
lack of adequate water required for cooling plant operations;
labor disputes;
disruptions in the delivery of electricity to our customers;
suppliers and contractors who do not perform as required under their contracts;
failure of other operators’ facilities and the effect of that failure on our electric system and customers;
inability to comply with regulatory or permit requirements, including those relating to environmental laws;
disruptions in the delivery of electricity to our customers;
handling, storage, and disposition of CCR;
unusual or adverse weather conditions or other natural disasters, including severe storms, droughts, floods, tornadoes, earthquakes, sustained high temperatures, solar flares, and electromagnetic pulses;
the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, pandemic health events, or other similar events;
accidents that might result in injury or loss of life, extensive property damage, or environmental damage;
ineffective vegetation management programs;
cybersecurity risks, including loss of operational control of Ameren Missouri’s energy centers and our transmission and distribution systems and loss of data, including sensitive customer, employee, financial, and operating system information, through insider or outsider actions;
failure of other operators’ facilities and the effect of that failure on our electric system and customers;
the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, pandemic health events, or other similar events;
limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities;
inability to implement or maintain information systems;
failure to keep pace with and the ability to adapt to rapid technological change; and
other unanticipated operations and maintenance expenses and liabilities.
The foregoing risks could affect the controls and operations of our facilities or impede our ability to meet regulatory requirements, which could increase operating costs, increase our capital requirements and costs, reduce our revenues or have an adverse effect on our liquidity.
Ameren Missouri’s ability to obtain an adequate supply of coal could limit operation of its coal-fired energy centers.
Ameren Missouri owns and operates coal-fired energy centers. About 97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming, which has a limited number of suppliers.Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion and maintenance, derailments, weather, and supplier financial hardship. Coal suppliers in the Power River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations, as well as concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2019, coal inventories for Ameren Missouri were near targeted levels. However, disruptions in the delivery of coal, failure of our coal suppliers to provide adequate quantities or quality of coal, or lack of adequate inventories of coal, including low-sulfur coal used to comply with environmental regulations, could have adverse effects on Ameren Missouri’s electric generation operations. If Ameren Missouri is unable to obtain an adequate supply of coal under existing agreements, it may be required to purchase coal at higher prices or be forced to reduce generation at its coal-fired energy centers, which could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Ameren Missouri’s ownership and operation of a nuclear energy center creates business, financial, and waste disposal risks.
Ameren Missouri’s ownership of the Callaway energy centerEnergy Center subjects it to risks associated with nuclear generation, including:
potential harmful effects on the environment and human health resulting from radiological releases associated with the operation of nuclear facilities and the storage, handling, and disposal of radioactive materials;
continued uncertainty regarding the federal government’s plan to permanently store spent nuclear fuel and, as a result, the need to provide for long-term storage of spent nuclear fuel at the Callaway energy center; | |
• | potential harmful effects on the environment and human health resulting from radiological releases associated with the operation of nuclear facilities and the storage, handling, and disposal of radioactive materials; |
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• | continued uncertainty regarding the federal government’s plan to permanently store spent nuclear fuel and, as a result, the need to provide for long-term storage of spent nuclear fuel at the Callaway Energy Center; |
limitations on the amounts and types of insurance available to cover losses that might arise in connection with the Callaway energy centerEnergy Center or other United States nuclear facilities, including losses due to market performance and other economic factors that adversely affect the value of the securities in the nuclear decommissioning trust fund;facilities;
uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway energy centerEnergy Center or any other United States nuclear facilities;
public and governmental concerns about the safety and adequacy of security at nuclear facilities;
limited availability of fuel supply and our reliance on licensed fuel assemblies from the one NRC-licensed supplier of Callaway Energy Center’s assemblies;
costly and extended outages for scheduled or unscheduled maintenance and refueling;
uncertainties about the technological and financial aspects of decommissioning nuclear facilities at the end of their licensed lives;
limited availability of fuel supply and our reliance on licensed fuel assemblies that are fabricated by Westinghouse, Callaway energy center’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;
costly and extended outages for scheduled or unscheduled maintenance and refueling;
the adverse effect of poor market performance and other economic factors on the asset values of nuclear decommissioning trust funds and the corresponding increase, upon MoPSC approval, in customer rates to fund the estimated decommissioning costs; and
potential adverse effects of a natural disaster, acts of sabotage or terrorism, including a cyber attack, or any accident leading to release of nuclear contamination.a radiological release.
The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear facilities. In the event of noncompliance, the NRC has the authority to impose fines or to shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated from time to time by the NRC could necessitate substantial capital expenditures at the Callaway energy center.Energy Center. In addition, if a serious nuclear incident were to occur, it could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial condition, and liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation of any domestic nuclear unit and could also cause the NRC to impose additional conditions or requirements on the industry, which could increase costs and result in additional capital expenditures. NRC standards
relating to seismic risk require Ameren Missouri to further evaluate the impact of an earthquake on its Callaway energy centerEnergy Center due to its proximity to a fault line, which could require the installation of additional capital equipment.
Our natural gas distribution and storage activities involve numerous risks that may result in accidents and increased operating costs that could adversely affect our results of operations, financial position, and liquidity.costs.
Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, explosions, mechanical problems and cybersecurity risks, which could cause substantial financial losses.losses, including fines and penalties. In addition, these hazards could result in serious injury, loss of human life, significant damage to property, environmental impacts, and impairment of our operations, which in turn could lead us to incur substantial losses. The location of distribution mains and storage facilities near populated areas, including residential areas, business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. A major domestic incident involving natural gas distribution and storage systems could lead toresult in additional capital expenditures for us and increased regulation and fines and penalties onof natural gas utilities. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
Significant portions of our electric generation, transmission, and distribution facilities and natural gas transmission and distribution facilities are aging. This aging infrastructure may require significant additional maintenance or replacementreplacement. Ameren Missouri could be adversely affected if it is unable to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that could adversely affect our results of operations, financial position,remaining investment and liquidity.those decommissioning costs.
Our aging infrastructure may pose risks to system reliability and expose us to expedited or unplanned significant capital expenditures and operating costs. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978, and the Callaway energy centerEnergy Center began operating in 1984. The age of these energy centers increases the risks of unplanned outages, reduced generation output, and higher maintenance expense. If, at the end of its life, an energy center’s cost has not been fully recovered, Further, Ameren Missouri may be adversely affected if the MoPSC does not allow such cost to be recovered in rates. Ameren Missouri may also be adversely affectedrecovery ofthe remaining investment, if the MoPSC does not allow full or timely recovery ofany, and decommissioning costs associated with the retirement of an energy center.center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. Aging transmission and distribution facilities are more prone to failure than new facilities, which results in higher maintenance expense and the need to replace these facilities with new infrastructure. Even if the system is properly maintained, its reliability may ultimately deteriorate and negatively affect our ability to serve our customers, which could result in increased costs associated with regulatory oversight. The frequency and duration of customer outages are among the IEIMA performance standards. Any failure to achieve these standards will result in a reduction in Ameren Illinois’ allowed return on equityROE on electric distribution assets. The higher maintenance costs associated with aging infrastructure and capital expenditures for new or replacement infrastructure could cause additional rate volatility for our customers, resistance by our regulators to allow customer rate increases, and/or regulatory lag in some of our jurisdictions, any of which could adversely affect our results of operations, financial position, and liquidity.
Energy conservation, energy efficiency, distributed generation, energy storage, technological advances, and other factors thatcould reduce energy demand could adversely affect Ameren andfrom Ameren Missouri’s results of operations, financial position, and liquidity.customers.
Without a regulatory mechanism to ensure recovery, declines in energy usage willcould result in an under-recovery of Ameren Missouri’s revenue requirement.requirement, which could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity. Such declines could occur due to a number of factors:
Conservation and energy-efficiency programs. Missouri allows for conservation and energy-efficiency programs that are designed to reduce energy demand.
Distributed generation and other energy-efficiency efforts. Ameren Missouri is exposed to declining usage from energy-efficiency efforts not related to its energy-efficiency programs, as well as from distributed generation sources, such as solar panels and other technologies. Ameren Missouri generates power at utility-scale energy centers to achieve economies of scale and to produce power at a competitive cost. Some distributed generation technologies have become more cost-competitive, with decreasing costs expected in the future. The costs of these distributed generation technologies may decline over time to a level that is competitive with that of Ameren Missouri’s energy centers. Additionally, technological advances in energy storage may be coupled with distributed generation to reduce the demand for our electric utility services. Increased adoption of these technologies by customers could decrease our revenues if customers cease to use our generation, transmission, and distribution services at current levels. Ameren Missouri might incur stranded costs, which ultimately might not be recovered through rates.
Macroeconomic factors. Macroeconomic factors resulting in low economic growth or contraction within Ameren Missouri’s service territories could reduce energy demand.
| |
| • | Conservation and energy-efficiency programs. Missouri allows for conservation and energy-efficiency programs that are designed to reduce energy demand. |
| |
| • | Distributed generation and other energy-efficiency efforts. Ameren Missouri is exposed to declining usage from energy-efficiency efforts not related to its energy-efficiency programs, as well as from distributed generation sources, such as solar panels and other technologies. Ameren Missouri generates power at utility-scale energy centers to achieve economies of scale. Some distributed generation technologies have become more cost-competitive, with decreasing costs expected in the future. The costs of these distributed generation technologies may decline over time to a level that is competitive with that of Ameren Missouri’s energy centers. Additionally, technological advances in energy storage may be coupled with distributed generation to reduce the demand for our electric utility services. Increased adoption of these technologies by customers could decrease our revenues if customers cease to use our generation, transmission, and distribution services at current levels. Ameren Missouri might incur stranded costs, which ultimately might not be recovered through rates. |
| |
| • | Macroeconomic factors. Macroeconomic factors resulting in low economic growth or contraction within Ameren Missouri’s service territories could reduce energy demand. |
We are subject to employee work force factors that could adversely affect our operations.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. ACertain specialized knowledge is required to construct and operate generation, transmission, and distribution assets. Further, a significant
portion of our work force is nearing retirement, including many employees with specialized skills, such as maintaining and servicing our electric and natural gas infrastructure and operating our energy centers.retirement. We are also party to collective bargaining agreements that collectively represent about 52%50% of Ameren’s total employees. AnyCertain events, such as an aging workforce without adequately trained replacement employees, the mismatch of skill sets or complement to future needs, or any work stoppage experienced in connection with negotiations of collective bargaining agreements, could adversely affect our operations.
Our operations are subject to acts of terrorism, cyber attacks, and other intentionally disruptive acts.
Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and information systems may be affected by terrorist activities and other intentionally disruptive acts, including cyber attacks, which could disrupt our ability to produce or distribute our energy products. Within our industry, thereThere have been attacks on energy infrastructure, such as substations and related assets, in the past, and there may be more attacks in the future. Any such incident could limit our ability to generate, purchase, or transmit power or natural gas and could have significant regional economic consequences. Any such disruption could result in a significant decrease in revenues, a significant increase in costs including those for repair, or adversely impactaffect economic activity in our service territory which, in turn, could adversely affect our results of operations, financial position, and liquidity.
There has been an increase in the number and sophistication of cyber attacks across all industries worldwide. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm resulting from theft or the inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected system. Therefore, a disruption caused by a cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. Insurance might not be adequate to cover losses that arise in connection with these events. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
FINANCIAL, ECONOMIC, AND MARKET RISKS
Our businesses are dependent on our ability to access the capital markets successfully. We might not have access to sufficient capital in the amounts and at the times needed.needed, as well as on reasonable terms.
We rely on the issuance of short-term and long-term debt and equity as significant sources of liquidity and funding for capital requirements not satisfied by our operating cash flow, as well as to refinance existing long-term debt. By the end of 2019, $951 million and $457 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these
senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. The inability to raise debt or equity capital aton reasonable terms, or at all, could negatively affect our ability to maintain and to expand our businesses. Events beyond our control, such as a recessiondepressed economic conditions or extreme volatility in the debt, equity, or credit markets, might create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity, or credit markets, including our ability to draw on bank credit facilities. Any adverse change in our credit ratings could reduce access to capital and trigger collateral postings and prepayments. Such changes could also increase the cost of borrowing and the costs of fuel, power, and natural gas supply, among other things, which could adversely affect our results of operations, financial position, and liquidity.
Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.
Ameren is a holding company; therefore, its primary assets are its investments in the common stock of its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. As a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s ability to service its debt obligations is dependent upon the earnings of its operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under affiliate indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations, and other items affecting retained earnings, and available cash. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of affiliate borrowing arrangements and cash payments under the tax allocation agreement) to Ameren. Certain financing agreements, corporate organizational documents, and certain statutory and regulatory requirements may impose restrictions on the ability of Ameren Missouri, Ameren Illinois, and ATXI to transfer funds to Ameren in the form of cash dividends, loans, or advances.
Increasing costs
Costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits could adversely affect our financial position and liquidity.increase.
Ameren offers defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren offers defined benefit pension plans covering substantially all of its non-union employees and postretirement benefit plans covering non-union employees hired before October 2015. Assumptions related to future costs, returns on investments, interest rates, timing of employee retirements, and mortality, as well as other actuarial matters, have a significant impact on our customers’ rates and our plan funding requirements. Ameren’s total unfunded obligation under its pension and postretirement benefit plans was $551$216 million as of December 31, 2017.2019. Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on Ameren’s assumptions at December 31, 2017,2019, its investment performance in 2017,2019, and its pension funding policy, Ameren expects to make annual contributions of less than $1 millionup to $60approximately $45 million in each of the next five years, with aggregate estimated contributions of $120$70 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements are estimated to be 35%30% and 55%60%, respectively. These amounts are estimates. Theyestimates may change with actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions.
In addition to the costs of our retirementpension plans, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. Future legislative changes related to health care could also significantly change our benefit programs and costs. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits could increase our financing needs and otherwise adversely affect our financial position and liquidity.
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| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
For information on our principal properties, see the energy center table below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of planned additions, replacements, or transfers. See also Note 5 – Long-term Debt and Equity Financings and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows the anticipated capability of Ameren Missouri’s energy centers at the time of Ameren Missouri’s expected 20182020 peak summer electrical demand:
|
| | | | |
| Primary Fuel Source | Energy Center | Location | Net Kilowatt Capability(a) |
| Coal | Labadie(b) | Franklin County, Missouri | 2,372,000 |
|
| | Rush Island(c) | Jefferson County, Missouri | 1,178,000 |
|
| | Sioux(d) | St. Charles County, Missouri | 972,000 |
|
| | Meramec(b)(e) | St. Louis County, Missouri | 591,000540,000 |
|
| Total coal | | | 5,113,0005,062,000 |
|
| Nuclear | Callaway(f) | Callaway County, Missouri | 1,194,000 |
|
| Hydroelectric | Osage(f) | Lakeside, Missouri | 240,000235,000 |
|
| | Keokuk | Keokuk, Iowa | 144,000 |
|
| Total hydroelectric | | | 384,000379,000 |
|
| Pumped-storage | Taum Sauk(f) | Reynolds County, Missouri | 440,000 |
|
| Natural gas (CTs) | Audrain(g) | Audrain County, Missouri | 608,000 |
|
| Venice(h) | Venice, Illinois | 494,000 |
|
| Goose Creek | Piatt County, Illinois | 438,000 |
|
| Pinckneyville | Pinckneyville, Illinois | 316,000 |
|
| Raccoon Creek | Clay County, Illinois | 308,000 |
|
| Meramec(e)(h)(i) | St. Louis County, Missouri | 272,000 |
|
| Kinmundy(h) | Kinmundy, Illinois | 210,000 |
|
| Peno Creek(g)(h) | Bowling Green, Missouri | 192,000 |
|
| Total natural gas | | | 2,838,000 |
|
| Oil (CTs) | Fairgrounds | Jefferson City, Missouri | 55,000 |
|
| Meramec | St. Louis County, Missouri | 55,000 |
|
| | Mexico | Mexico, Missouri | 54,000 |
|
| | Moberly | Moberly, Missouri | 54,000 |
|
| | Moreau | Jefferson City, Missouri | 54,000 |
|
| Total oil | | | 272,000217,000 |
|
Natural gas (CTs) | Audrain(c)
| Audrain County, Missouri | 608,000 |
|
| Venice(d)
| Venice, Illinois | 491,000 |
|
| Goose Creek | Piatt County, Illinois | 438,000 |
|
| Pinckneyville | Pinckneyville, Illinois | 316,000 |
|
| Raccoon Creek | Clay County, Illinois | 304,000 |
|
| Meramec(b)(d)(e)
| St. Louis County, Missouri | 281,000 |
|
| Kinmundy(d)
| Kinmundy, Illinois | 208,000 |
|
| Peno Creek(c)(d)
| Bowling Green, Missouri | 192,000 |
|
Total natural gas | | | 2,838,000 |
|
| Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 8,000 |
|
| Solar | O’Fallon | O’Fallon, Missouri | 3,000 |
|
| Lambert | St. Louis County, Missouri | 1,000 |
|
| BJC | St. Louis, Missouri | 1,000 |
|
| Total solar | | | 5,000 |
|
| Total Ameren and Ameren Missouri | | | 10,252,00010,141,000 |
|
| |
| (a) | Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid. |
| |
| (b) | All coal-fueledThe Labadie Energy Center is scheduled to retire 1,186,000 kilowatts by 2036 and 236,000 natural-gas-fueled1,186,000 kilowatts at the Meramec energy center are scheduled for retirement in 2022.by 2042. |
| |
| (c) | There are economic development lease arrangements applicableThe Rush Island Energy Center is scheduled to these CTs.retire all generating capacity by 2045. |
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| (d) | The Sioux Energy Center is scheduled to retire all generating capacity by 2033. |
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| (e) | The Meramec Energy Center is scheduled for retirement by 2022. |
| |
| (f) | The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively. |
| |
| (g) | There are economic development arrangements applicable to these CTs, as discussed below. |
| |
| (h) | These CTs have the capability to operate on either oil or natural gas (dual fuel). |
| |
(e)(i) | Two of its three units are steam-powered. |
The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2017:2019:
| | | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois |
Circuit miles of electric transmission lines(a) | 2,970 |
| | 4,638 |
| 2,971 |
| | 4,643 |
|
| Circuit miles of electric distribution lines | 33,414 |
| | 45,899 |
| 33,652 |
| | 45,868 |
|
| Percentage of circuit miles of electric distribution lines underground | 23 | % | | 15 | % | 24 | % | | 16 | % |
| Miles of natural gas transmission and distribution mains | 3,379 |
| | 18,393 |
| 3,448 |
| | 18,503 |
|
| Underground natural gas storage fields | — |
| | 12 |
| — |
| | 12 |
|
| Total working capacity of underground natural gas storage fields in billion cubic feet | — |
| | 24 |
| — |
| | 24 |
|
| |
| (a) | ATXI owns 303505 miles of transmission lines not reflected in this table. |
Our other properties include office buildings, warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all principal energy centers and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bonds and to certain permitted liens and judgment liens). The exceptions are as follows:
A portion of Ameren Missouri’s Osage energy centerEnergy Center reservoir, certain facilities at Ameren Missouri’s Sioux energy center,Energy Center, most of Ameren Missouri’s Peno Creek and Audrain CT energy centers, Ameren Missouri’s Maryland Heights Energy Center, Ameren Missouri’s Lambert and BJC energy center,centers, certain substations, and most transmission and distribution lines and natural gas mains are situated on lands occupied under leases, easements, franchises, licenses, or permits. The United States or the state of Missouri may own or may have paramount rights with respect to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which certain of Ameren Missouri’s energy centers and other properties are located.
The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of Ameren Missouri’s Keokuk energy centerEnergy Center is located.
Substantially all of the properties and plant of Ameren Missouri and Ameren Illinois are subject to the liens of the indentures securing their mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek CT energy centerEnergy Center to the city of Bowling Green, Missouri through 2022. Ameren Missouri has rights and leasedobligations as the operator of the energy center back fromunder a long-term agreement with the city through 2022.of Bowling Green. Under the terms of this capital lease,agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the lease,agreement, at which time the property, plant, and equipment will become subject to the lien of anythe Ameren Missouri first mortgage bond indenture then in effect.indenture.
Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as lesseethe operator of the CT energy center under a long-term leaseagreement with Audrain County. The lease will expire in December 2023. Under the terms of this capital lease,agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. The agreement will expire in December 2023. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the lease,agreement, at which time the property, plant, and equipment will become subject to the lien of anythe Ameren Missouri first mortgage bond indenture then in effect.indenture.
In May 2019, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 300-megawatt wind generation facility. In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 400-megawatt wind generation facility. Both facilities are expected to be completed by the end of 2020 and would support Ameren Missouri’s compliance with the Missouri renewable energy standard. For additional information on these agreements, see Note 2 – Rate and Regulatory Matters under Part II, Item 8 of this report.
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. Material legal and administrative proceedings, which are discussed in 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 and are incorporated herein by reference, include the following:
Ameren Missouri’s proceedingelectric service regulatory rate review filed with the MoPSC to investigate how the effect of the reduction in the federal statutory corporate income tax rate enacted under TCJA should be reflected in rates paid by electric and natural gas customers;
Ameren Illinois’ proceeding with the ICC to pass through to its natural gas customers the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA;July 2019;
Ameren Illinois’ natural gas delivery service regulatory rate review filed with the ICC in January 2018;February 2020;
the request filedICC’s QIP prudence review requested by MISO participants, including Ameren Illinois in March 2019;
Ameren and ATXI, with the FERC to allow revisions to 2018 electricMISO transmission rates to reflect the impactsowner’s request for a rehearing of the reduction inNovember 2019 FERC order related to the federal statutory corporate income tax rate enacted under the TCJA;November 2013 complaint case;
the February 2015 complaint case filed with theMarch 2019 FERC seeking a reduction in theseparate Notices of Inquiry regarding its allowed base return on common equity under the MISO tariff;ROE policy and its transmission incentives policy;
litigation against Ameren Missouri with respect to NSR and the EPA Clean Air Act; and
remediation matters associated with former MGP and waste disposal sites of the Ameren Companies.Illinois.
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| ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):OFFICERS:
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 20172019, all their positions and offices held with the Ameren Companies as of February 15, 2018,14, 2020, their tenures as officers, and their business backgrounds for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.
AMEREN CORPORATION:
|
| | | | |
| Name | Age | | Positions and Offices Held |
| | | | |
| Warner L. Baxter | 5658 |
| | Chairman, President and Chief Executive Officer, and Director |
| Baxter joined Ameren Missouri in 1995. He was elected to the positions of executive vice president and chief financial officer of Ameren, Ameren Missouri, Ameren Illinois, and Ameren Services in 2003. He was elected chairman, president, chief executive officer, and chief financial officer of Ameren Services in 2007. In 2009, he was elected chairman, president, and chief executive officer of Ameren Missouri. In 2014, he was elected chairman, president, and chief executive officer of Ameren, and relinquished his positions at Ameren Missouri. |
| | | | |
Martin J. Lyons, Jr.Michael L. Moehn
| 5150 |
| | Executive Vice President and Chief Financial Officer |
LyonsMoehn joined Ameren Services in 2001.2000. In 2004, he was elected vice president, corporate planning, of Ameren Services. In 2008, he was elected senior vice president, corporate planning and chief accounting officerbusiness risk management, of the Ameren Companies.Services. In 2009,2012, he was also elected chief financial officersenior vice president, customer operations, of the Ameren Companies.Missouri, and relinquished his position at Ameren Services. In 2013,2014, he was elected chairman and president of Ameren Missouri. In December 2019, he was elected executive vice president and chief financial officer of the Ameren Companies and relinquished his duties as chief accounting officer. In 2016, he was elected chairman and president of Ameren Services.Services and relinquished his positions at Ameren Missouri. |
| | | | |
Gregory L. NelsonChonda J. Nwamu | 6048 |
| | Senior Vice President, General Counsel, and Secretary |
NelsonNwamu joined Ameren MissouriServices in 1995. He was electedSeptember 2016 as vice president and tax counsel of Ameren Services in 1999 anddeputy general counsel. In January 2019, she was elected senior vice president of Ameren Missouri and Ameren Illinois in 2003. In 2010, he was elected vice president, tax and deputy general counsel of Ameren Services. He remained vice president of Ameren Missouri and Ameren Illinois. In 2011, heAugust 2019, she was elected senior vice president, general counsel and secretary of the Ameren Companies. Prior to joining Ameren Services, she served as regulatory counsel at Pacific Gas and Electric Company, a public utility, from 2000 to May 2014 and as managing counsel and senior director from June 2014 to June 2016. |
| | | | |
| Bruce A. Steinke | 5658 |
| | Senior Vice President, Finance, and Chief Accounting Officer |
| Steinke joined Ameren Services in 2002. In 2008, he was elected vice president and controller of Ameren, Ameren Illinois, and Ameren Services. In 2009, he relinquished his positions at Ameren Illinois. In 2013, he was elected senior vice president, finance, and chief accounting officer of the Ameren Companies. |
SUBSIDIARIES:
|
| | | | |
| Name | Age | | Positions and Offices Held |
| | | |
| Bhavani Amirthalingam | 44 |
| | Senior Vice President and Chief Digital Information Officer (Ameren Services) |
| Amirthalingam joined Ameren Services in March 2018 as senior vice president and chief digital information officer. She served as the chief information officer and vice president North America for Schneider Electric SE, an energy management and automation solutions company, from January 2015 to March 2018 and in various roles at World Wide Technology Inc., a technology solution provider, from November 1999 to January 2015, most recently serving as vice president of customer solutions and innovation from September 2013 to January 2015. |
| | | |
| Mark C. Birk | 5355 |
| | Senior Vice President, Customer and Power Operations (Ameren Missouri) |
Birk joined Ameren Missouri in 1986. In 2005,2004, he was elected vice president, power operations, of Ameren Missouri. In 2012, he was elected senior vice president, corporate planning, of Ameren Services. In 2014, he was also elected senior vice president, oversight, of Ameren Services, and in 2015, he was elected senior vice president, corporate safety, planning and operations oversight. In January 2017, he was elected senior vice president, customer operations, at Ameren Missouri and relinquished his positions at Ameren Services. In October 2017, he was elected senior vice president, customer and power operations, at Ameren Missouri. |
| | | | |
| Fadi M. Diya | 5557 |
| | Senior Vice President and Chief Nuclear Officer (Ameren Missouri) |
| Diya joined Ameren Missouri in 2005. In 2008, he was elected vice president, nuclear operations, of Ameren Missouri. In 2014, he was elected senior vice president and chief nuclear officer of Ameren Missouri. |
| | | | |
| Mary P. Heger | 6163 |
| | Senior Vice President, and Chief Information OfficerCustomer Experience (Ameren Services)Illinois) |
Heger joined Ameren Missouri in 1976. In 2009, she was elected vice president, information technology, of Ameren Services, and in 2012,2013, she was also elected chief information officer of Ameren Services. In September 2015, she was elected senior vice president and chief information officer of Ameren Services. In February 2019, she was elected senior vice president, customer experience, at Ameren Illinois and relinquished her position at Ameren Services. |
| | | | |
| Mark C. Lindgren | 5052 |
| | Senior Vice President, Corporate Communications, and Chief Human Resources Officer (Ameren Services) |
| Lindgren joined Ameren Services in 1998. In 2009, he was elected vice president, human resources, of Ameren Services, and in 2012, he was also elected chief human resources officer of Ameren Services. In September 2015, he was elected senior vice president, corporate communications, and chief human resources officer of Ameren Services. |
| | | | |
| Richard J. Mark | 6264 |
| | Chairman and President (Ameren Illinois) |
| Mark joined Ameren Services in 2002 as vice president, customer service. In 2003, he was elected vice president, governmental policy and consumer affairs, of Ameren Services. In 2005, he was elected senior vice president, customer operations, of Ameren Missouri. In 2007, he relinquished his position at Ameren Services. In 2012, he relinquished his position at Ameren Missouri and was elected chairman and president of Ameren Illinois. |
| | | | |
Michael L. MoehnMartin J. Lyons, Jr. | 4853 |
| | Chairman and President (Ameren Missouri) |
MoehnLyons joined Ameren Services in 2000. In 2004, he was elected vice president, corporate planning, of Ameren Services.2001. In 2008, he was elected senior vice president corporate planning and business risk management,chief accounting officer of the Ameren Services.Companies. In 2012,2009, he was also elected chief financial officer of the Ameren Companies. In 2013, he was elected seniorexecutive vice president customer operations,and chief financial officer of the Ameren Missouri,Companies, and relinquished his position at Ameren Services.duties as chief accounting officer. In 2014,March 2016, he was elected chairman and president of Ameren Missouri.Services. In December 2019, he was elected chairman and president of Ameren Missouri and relinquished his position as executive vice president and chief financial officer of the Ameren Companies and his positions at Ameren Services. |
| | | | |
| Shawn E. Schukar | 5658 |
| | Chairman and President (ATXI) |
| Schukar joined a predecessor company of Ameren Illinois in 1984. In 2005, he was elected vice president, commercial RTO operations, of Ameren Services. In 2013, he was elected senior vice president, transmission operations, construction and project management, of ATXI. In May 2017, he was elected chairman and president of ATXI. |
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the executive officers or between any executive officers and any directors of the Ameren Companies. All ofExcept as noted, the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
PART II
| |
| ITEM 5. | MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES |
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 47,74843,576 on January 31, 20182020. The following table presents the price ranges, closing prices, and dividends declared per Ameren common share for each quarter during 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| | High | | Low | | Close | | Dividends Declared |
| 2017 Quarter Ended: | | | | | | | |
| March 31 | $ | 56.57 |
| | $ | 51.35 |
| | $ | 54.59 |
| | $ | 0.44 |
|
| June 30 | 57.21 |
| | 53.72 |
| | 54.67 |
| | 0.44 |
|
| September 30 | 60.91 |
| | 53.54 |
| | 57.84 |
| | 0.44 |
|
| December 31 | 64.89 |
| | 57.67 |
| | 58.99 |
| | 0.4575 |
|
| 2016 Quarter Ended: | | | | | | | |
| March 31 | $ | 50.16 |
| | $ | 41.50 |
| | $ | 50.10 |
| | $ | 0.425 |
|
| June 30 | 53.59 |
| | 46.29 |
| | 53.58 |
| | 0.425 |
|
| September 30 | 54.08 |
| | 47.79 |
| | 49.18 |
| | 0.425 |
|
| December 31 | 52.88 |
| | 46.84 |
| | 52.46 |
| | 0.44 |
|
There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding common stock of Ameren Missouri and Ameren Illinois.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its registrant subsidiaries during 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 | | | 2016 |
| (In millions) | Quarter Ended | | | Quarter Ended |
| Registrant | December 31 | | September 30 | | June 30 | | March 31 | | | December 31 | | September 30 | | June 30 | | March 31 |
| Ameren Missouri | $ | 30 |
| | $ | 160 |
| | $ | 112 |
| | $ | 60 |
| | | $ | 70 |
| | $ | 75 |
| | $ | 70 |
| | $ | 140 |
|
| Ameren Illinois | — |
| | — |
| | — |
| | — |
| | | 15 |
| | 35 |
| | 30 |
| | 30 |
|
| Ameren | 111 |
| | 106 |
| | 107 |
| | 107 |
| | | 107 |
| | 103 |
| | 103 |
| | 103 |
|
On February 9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 45.75 cents per share. The common share dividend is payable March 29, 2018, to shareholders of record on March 14, 2018.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see 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.
Purchases of Equity Securities
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 | | (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 |
October 1 – October 31, 2017 | — |
| | $ | — |
| | — |
| | — |
|
November 1 – November 30, 2017(a) | 5,232 |
| | 62.35 |
| | — |
| | — |
|
December 1 – December 31, 2017 | — |
| | — |
| | — |
| | — |
|
| Total | 5,232 |
| | $ | 62.35 |
| | — |
| | — |
|
| |
(a) | The shares of Ameren common stock were purchased in open-market transactions in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards issued under its stock-based compensation plans. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
Corporation, Ameren Missouri, and Ameren Illinois did not purchase any equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 20172019, to December 31, 20172019.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder returnTSR during the five years ended December 31, 20172019. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI Index), which comprises most investor-owned electric utilities inS&P 500 Index, S&P 500 Utility Index, and the United States.Philadelphia Utility Index. The EEI Index, S&P 500 Utility Index, and the Philadelphia Utility Index are market capitalization-weighted indices of U.S. public utility companies. The comparison assumes that $100 was invested on December 31, 20122014, in Ameren common stock and in each of the indices shown and it assumes that all of the dividends were reinvested.
Comparison of Five-Year Cumulative Return
| | | December 31, | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
| Ameren (AEE) | $ | 100.00 |
| | $ | 123.31 |
| | $ | 163.67 |
| | $ | 159.79 |
| | $ | 200.79 |
| | $ | 232.84 |
| $ | 100.00 |
| | $ | 97.63 |
| | $ | 122.68 |
| | $ | 142.26 |
| | $ | 162.15 |
| | $ | 195.91 |
|
| EEI Index | | 100.00 |
| | 96.10 |
| | 112.86 |
| | 126.09 |
| | 130.71 |
| | 164.43 |
|
| S&P 500 Index | 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
| 100.00 |
| | 101.38 |
| | 113.51 |
| | 138.28 |
| | 132.23 |
| | 173.86 |
|
| EEI Index | 100.00 |
| | 113.01 |
| | 145.68 |
| | 140.00 |
| | 164.42 |
| | 183.69 |
| |
| S&P 500 Utility Index | | 100.00 |
| | 95.15 |
| | 110.65 |
| | 124.05 |
| | 129.15 |
| | 163.18 |
|
| Philadelphia Utility Index | | 100.00 |
| | 93.83 |
| | 110.37 |
| | 124.03 |
| | 128.45 |
| | 163.00 |
|
Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.
| |
| ITEM 6. | SELECTED FINANCIAL DATA |
| | | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | |
Ameren(a): | | | | | | | | | | |
| Ameren: | | | | | | | | | | | |
| Operating revenues | $ | 6,177 |
| | $ | 6,076 |
| | $ | 6,098 |
| | $ | 6,053 |
| | $ | 5,838 |
| $ | 5,910 |
| | $ | 6,291 |
| | $ | 6,174 |
| | $ | 6,076 |
| | $ | 6,098 |
| (a) |
Operating income(b) | 1,458 |
| | 1,381 |
| | 1,259 |
| | 1,254 |
| | 1,184 |
| |
| Operating income | | 1,267 |
| | 1,357 |
| | 1,410 |
| | 1,322 |
| | 1,235 |
| (a)(b) |
Income from continuing operations(c) | 529 |
| | 659 |
| | 585 |
| | 593 |
| | 518 |
| 834 |
| | 821 |
| | 529 |
| (c) | 659 |
| | 585 |
| |
Income (loss) from discontinued operations, net of taxes(d) | — |
| | — |
| | 51 |
| | (1 | ) | | (223 | ) | |
| Income from discontinued operations, net of taxes | | — |
| | — |
| | — |
| | — |
| | 51 |
| |
| Net income attributable to Ameren common shareholders | 523 |
| | 653 |
| | 630 |
| | 586 |
| | 289 |
| 828 |
| | 815 |
| | 523 |
| | 653 |
| | 630 |
| |
| Common stock dividends | 431 |
| | 416 |
| | 402 |
| | 390 |
| | 388 |
| 472 |
| | 451 |
| | 431 |
| | 416 |
| | 402 |
| |
| Continuing operations earnings per share – basic | 2.16 |
| | 2.69 |
| | 2.39 |
| | 2.42 |
| | 2.11 |
| 3.37 |
| | 3.34 |
| | 2.16 |
| | 2.69 |
| | 2.39 |
| |
| Continuing operations earnings per share – diluted | 2.14 |
| | 2.68 |
| | 2.38 |
| | 2.40 |
| | 2.10 |
| 3.35 |
| | 3.32 |
| | 2.14 |
| | 2.68 |
| | 2.38 |
| |
| Common stock dividends per share | 1.778 |
| | 1.715 |
| | 1.655 |
| | 1.61 |
| | 1.60 |
| 1.9200 |
| | 1.8475 |
| | 1.7775 |
| | 1.715 |
| | 1.655 |
| |
| As of December 31: | | | | | | | | | | | | | | | | | | | |
Total assets(e) | $ | 25,945 |
| | $ | 24,699 |
| | $ | 23,640 |
| | $ | 22,289 |
| | $ | 20,907 |
| |
| Total assets | | $ | 28,933 |
| | $ | 27,215 |
| | $ | 25,945 |
| | $ | 24,699 |
| | $ | 23,640 |
| |
| Long-term debt, excluding current maturities | 7,094 |
| | 6,595 |
| | 6,880 |
| | 6,085 |
| | 5,475 |
| 8,915 |
| | 7,859 |
| | 7,094 |
| | 6,595 |
| | 6,880 |
| |
| Total Ameren Corporation shareholders’ equity | 7,184 |
| | 7,103 |
| | 6,946 |
| | 6,713 |
| | 6,544 |
| 8,059 |
| | 7,631 |
| | 7,184 |
| | 7,103 |
| | 6,946 |
| |
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 3,539 |
| | $ | 3,523 |
| | $ | 3,609 |
| | $ | 3,553 |
| | $ | 3,541 |
| $ | 3,243 |
| | $ | 3,589 |
| | $ | 3,537 |
| | $ | 3,524 |
| | $ | 3,609 |
| (a) |
Operating income(b) | 747 |
| | 745 |
| | 742 |
| | 785 |
| | 803 |
| |
| Operating income | | 617 |
| | 749 |
| | 722 |
| | 725 |
| | 742 |
| (a)(b) |
Net income available to common shareholder(c) | 323 |
| | 357 |
| | 352 |
| | 390 |
| | 395 |
| 426 |
| | 478 |
| | 323 |
| (c) | 357 |
| | 352 |
| |
| Dividends to parent | 362 |
| | 355 |
| | 575 |
| | 340 |
| | 460 |
| 430 |
| | 375 |
| | 362 |
| | 355 |
| | 575 |
| |
| As of December 31: | | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 14,043 |
| | $ | 14,035 |
| | $ | 13,851 |
| | $ | 13,474 |
| | $ | 12,867 |
| $ | 14,937 |
| | $ | 14,291 |
| | $ | 14,043 |
| | $ | 14,035 |
| | $ | 13,851 |
| |
| Long-term debt, excluding current maturities | 3,577 |
| | 3,563 |
| | 3,844 |
| | 3,861 |
| | 3,631 |
| 4,098 |
| | 3,418 |
| | 3,577 |
| | 3,563 |
| | 3,844 |
| |
| Total shareholders’ equity | 4,081 |
| | 4,090 |
| | 4,082 |
| | 4,052 |
| | 3,993 |
| 4,349 |
| | 4,229 |
| | 4,081 |
| | 4,090 |
| | 4,082 |
| |
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 2,528 |
| | $ | 2,490 |
| | $ | 2,466 |
| | $ | 2,498 |
| | $ | 2,311 |
| $ | 2,527 |
| | $ | 2,576 |
| | $ | 2,527 |
| | $ | 2,489 |
| | $ | 2,466 |
| (a) |
| Operating income | 580 |
| | 544 |
| | 466 |
| | 450 |
| | 415 |
| 550 |
| | 512 |
| | 569 |
| | 519 |
| | 446 |
| (a) |
| Net income available to common shareholder | 268 |
| | 252 |
| | 214 |
| | 201 |
| | 160 |
| 343 |
| | 304 |
| | 268 |
| | 252 |
| | 214 |
| |
| Dividends to parent | — |
| | 110 |
| | — |
| | — |
| | 110 |
| — |
| | — |
| | — |
| | 110 |
| | — |
| |
| As of December 31: | | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 10,345 |
| | $ | 9,474 |
| | $ | 8,903 |
| | $ | 8,204 |
| | $ | 7,397 |
| $ | 12,185 |
| | $ | 11,319 |
| | $ | 10,345 |
| | $ | 9,474 |
| | $ | 8,903 |
| |
| Long-term debt, excluding current maturities | 2,373 |
| | 2,338 |
| | 2,342 |
| | 2,224 |
| | 1,844 |
| 3,575 |
| | 3,296 |
| | 2,373 |
| | 2,338 |
| | 2,342 |
| |
| Total shareholders’ equity | 3,310 |
| | 3,034 |
| | 2,897 |
| | 2,661 |
| | 2,448 |
| 4,132 |
| | 3,774 |
| | 3,310 |
| | 3,034 |
| | 2,897 |
| |
| |
| (a) | Includes amountsAmounts have not been revised to reflect the adoption of accounting guidance on revenue from contracts with customers, effective for the Ameren registrantCompanies as of January 1, 2018, and nonregistrant subsidiaries and intercompany eliminations.are not comparative. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of our Form 10-K for the year ended December 31, 2018, filed with the SEC on February 26, 2019, for additional information. |
| |
| (b) | Includes a $69 million provision recorded in 2015 for all of the previously capitalized COLconstruction and operating license costs relating to the cancelled second nuclear unit at itsAmeren Missouri’s Callaway energy center. Energy Center. |
| |
| (c) | Includes an increase to income tax expense of $154 million and $32 million recorded in 2017 as a result of the TCJA at Ameren and Ameren Missouri, respectively. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information. |
| |
(d) | See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. |
| |
(e) | Includes total assets from discontinued operations of $165 million at December 31, 2013, and immaterial balances at December 31, 2017, 2016, 2015, and 2014. Total assets from discontinued operations are included in “Other current assets” on Ameren’s balance sheet. |
| |
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Ameren, 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 including– Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as the provision ofproviding shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise. 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 in the MISO. |
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 developing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and placed the Spoon River project in service in February 2018.
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 is primarily composedconsists of the aggregated electric transmission businesses of Ameren Illinois and ATXI.ATXI. See Note 1516 – Segment Information under Part II, Item 8, of this report for further discussion of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ Segments.
Unless otherwise stated, the following sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations exclude discontinued operations for all periods presented. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information regarding that presentation.
Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated.eliminated, except as disclosed inNote 13 – Related-party Transactions under Part II, Item 8, of this report. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular and graphical dollar amounts are in millions, unless otherwise indicated.
The following discussion should be read in conjunction with the financial statements contained in this Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Discussion regarding our financial condition and results of operations for the year ended December 31, 2017, including comparisons with the year ended December 31, 2018, is included in Item 7 of our Form 10-K for the year ended December 31, 2018, filed with the SEC on February 26, 2019.
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
OVERVIEW
Our core strategy to invest in regulated infrastructure, continuously improve performance, and advocate for responsible policies to deliver superior customer and shareholder value is driven by three pillars.
|
| | | | | |
| Investing in and operating our utilities in a manner consistent with existing regulatory frameworks | | Enhancing regulatory frameworks and advocating for responsible energy and economic policies | | Creating and capitalizing on opportunities for investment for the benefit of our customers and shareholders |
| We seek to earn competitive returns on investments in our businesses. Accordingly, we remain focused on disciplined cost management and strategic capital allocation. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators, to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned ROEs and allocating capital resources to business opportunities that we expect will provide the most benefit to our customers and offer the most attractive risk-adjusted return potential. | | We seek to partner with our stakeholders, including our customers, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers and shareholders. We believe constructive regulatory frameworks for investment exist at all of Ameren's business segments. Accordingly, we expect to earn competitive returns on investments in our businesses and realize timely recovery of our costs in the coming years with the benefits accruing to both customers and shareholders. | | We seek to make prudent investments that benefit our customers. The goal of these investments is to maintain and enhance the reliability of our services, develop cleaner sources of energy, create economic development opportunities in our region, and provide customers with more options and greater control over their energy usage, among other things. By prudently investing in our businesses, we believe that we deliver superior value to both customers and shareholders. |
| | Customer Rates, (¢/KWH)(d) |
| | |
Rate Base ($ in billions)(a) | | Constructive Regulatory Frameworks | | TSR 2014-2019(e) |
| | Segment | Regulatory Framework | | |
| Ameren Transmission | Formula ratemaking Allowed ROE is 10.38% | |
| Ameren Illinois Natural Gas | Future test year ratemaking and QIP, PGA, VBA Allowed ROE is 9.87% | |
| Ameren Illinois Electric Distribution | Formula ratemaking Allowed ROE is 30-year U.S. Treasury + 5.8% | |
| Ameren Missouri | Historical test year ratemaking and PISA, RESRAM, FAC, MEEIA Allowed ROE is 9.2% - 9.7%(c) | |
| | |
(a) Reflects year-end rate base except for Ameren Transmission, which is average rate base.
(b) Compound annual growth rate.
(c) Allowed ROE applicable to electric service.
(d) Average residential electric prices. Source: Edison Electric Institute, “Typical Bills and Average Rates Report” for the 12 months ended June 30, 2019.
(e) Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.
Below are some key announcements, updates, legislative actions, and regulatory outcomes that occurred in 2019 and early 2020.
In March 2019, Ameren issued its Building a Cleaner Energy Future report, which sets forth Ameren’s plan for reducing carbon emissions and addressing climate risk. The plan is largely reflected in the Ameren Missouri 2017 IRP, which includes expanding renewable sources by adding 700 megawatts of wind generation by the end of 2020 and adding 100 megawatts of solar generation by 2027. Ameren Missouri expects to file its next integrated resource plan in September 2020.
In August 2019, Ameren entered into a forward sale agreement with a counterparty relating to 7.5 million shares of common stock.The forward sale agreement can be settled at Ameren’s discretion on or prior to March 31, 2021. On a settlement date or dates, if Ameren elects to physically settle the forward sale agreement, Ameren will issue shares of common stock to the counterparty at the then-applicable forward sale price.The forward sale agreement will be physically settled unless Ameren elects to settle in cash or to net share settle. If physically settled, Ameren expects to receive between $540 million and $550 million upon settlement, which is expected to be used to fund a portion of Ameren Missouri’s wind generation investments. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.
Consistent with its 2017 IRP filing, in May 2019, Ameren Missouri entered into a build-transfer agreement to earnings per shareacquire, after construction, an up-to 300-megawatt wind generation facility.In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to400-megawatt wind generation facility. These two agreements are based on average diluted common shares outstanding for the relevant period.
OVERVIEW
Ameren’s strategic plan includes investing in,subject to customary contract terms and operating its utilities in, a manner consistent with existing regulatory frameworks, enhancing those frameworks, and advocating for responsible energy and economic policies, as well as creating and capitalizing on opportunities for investment for the benefit of its customers and shareholders. Ameren remains focused on disciplined cost management and strategic capital allocation. In 2017, Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks. It invested $1.4conditions. The two build-transfer acquisitions collectively represent $1.2 billion of capital expenditures, are expected to be completed by the end of 2020, and would support Ameren Missouri’s compliance with the Missouri renewable energy standard. Both acquisitions have received all regulatory approvals, and both projects have received all applicable zoning approvals, have entered into RTO interconnection agreements, and have begun construction activities.The MoPSC has approved a RESRAM, which is designed to mitigate the impacts of regulatory lag for the cost of compliance with Missouri’s renewable energy standard, including recovery of investments in wind and other renewable energy generation, by providing more timely recovery of costs and a return on investments not already provided for in customer rates or recovered under the PISA. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information regarding Ameren Missouri wind generation facilities.
In July 2019, Ameren Missouri filed a request with the MoPSC seeking approval to decrease its annual revenues for electric service by $1 million. In February 2020, Ameren Missouri, the MoPSC staff, the MoOPC, and certain intervenors filed a nonunanimous stipulation and agreement with the MoPSC to decrease Ameren Missouri’s annual revenues for electric service by $32 million. The remaining intervenor did not object to the agreement. The stipulation and agreement, which is subject to MoPSC approval, specified an allowed ROE range of 9.4% to 9.8%, but did not specify the common equity percentage or rate base. The stipulation and agreement includes the continued use of the FAC and trackers that the MoPSC previously authorized in earlier electric rate orders. Ameren Missouri cannot predict whether the MoPSC will approve the stipulation and agreement or, if approved, whether any application for rehearing or appeal will be filed, or the outcome if so filed. A decision by the MoPSC is expected by March 2020, with new rates effective as early as April 1, 2020.The percentage of net energy cost variances from the amount set in base rates allowed to be recovered or refunded under the FAC and costs from services provided by affiliates are still being challenged by the MoOPC, and are expected to be addressed in a proceeding that would begin in March 2020. A MoPSC decision would be expected in the proceeding by the end of May 2020.If a change to the percentage of net energy cost variances from the amount set in base rates allowed to be recovered or refunded under the FAC is ordered by the MoPSC, the ordered percentage will be reflected in the FAC. If any investments or expenses are disallowed by the MoPSC, the effect on customer rates of such disallowances will be deferred as a regulatory liability and refunded to customers over a period of time determined in the next regulatory rate review. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information regarding the Ameren Missouri 2019 electric service regulatory rate review.
In September 2019, the United States District Court for the Eastern District of Missouri issued an order in a case brought by the Department of Justice, on behalf of the EPA, alleging that in performing projects at its coal-fired Rush Island Energy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. The order requires Ameren Missouri to install a flue gas desulfurization system at the Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. In October 2019, Ameren Missouri appealed the district court’s ruling to the United States Court of Appeals for the Eighth Circuit. Additionally, in October 2019, following a request by Ameren Missouri, the district court stayed implementation of the majority of its order requirements while the case is appealed. As a result of the district court’s stay, Ameren Missouri does not expect to make significant capital expenditures or incur operations and maintenance expenses related to the district court’s order while the case is under appeal. The ultimate resolution of this matter could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for more information regarding NSR and clean air litigation.
In February 2020, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2020. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $7.6 billion over the five-year period from 2020 through 2024, with expenditures largely recoverable under the PISA and the RESRAM. As a part of its Smart Energy Plan, Ameren Missouri expects to build solar generation facilities, including utility scale facilities and nonresidential customer site facilities. In September 2019, Ameren Missouri filed for certificates of convenience and necessity with the MoPSC to build three solar facilities in its FERC rate-regulatedservice territory. Each 10-megawatt solar energy generation facility will connect to battery storage in order to improve system reliability. All three facilities are expected to be completed by 2022. Also in 2019, the MoPSC approved Ameren Missouri’s Charge Ahead program, which provides incentives for the development of over 1,000 electric transmissionvehicle charging stations along highways and Illinoisat various locations in communities throughout Ameren Missouri’s service territory. The purpose of the program is to promote the development of electric vehicle charging infrastructure that will enable long-distance electric vehicle travel and natural gas distribution businesses.encourage electrification of the transportation sector.
In March 2017,February 2020, the MoPSC issued an order approving a unanimous stipulation and agreement inallowing Ameren Missouri’s July 2016 regulatory rate review. The electric rate order resulted in a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in the base level of net energy costs,Missouri to defer and a $26 million reduction in the base level of certain trackedamortize maintenance expenses comparedrelated to scheduled refueling and maintenance outages at its Callaway Energy Center.Beginning with the amounts in the MoPSC’s April 2015 rate order. The new ratesfall 2020 refueling and base level of expenses became effective on April 1, 2017. In September 2017,maintenance outage, Ameren Missouri filed its nonbinding 20-year integrated resource plan with the MoPSC. This plan 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 sources by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, and adding 100 megawatts of solar generation over the next 10 years. These new renewable energy sources would support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to customer rate increase limitations. The plan also provides for expanding renewable generation, 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. The new renewable energy sources identified in Ameren Missouri’s plan could represent incremental investments of approximately $1 billion through 2020. In connection with the integrated resource plan filing, Ameren Missouri established a goal of reducing CO2 emissions 80% by
2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of its useful life.
In January 2017, Ameren Illinois implemented provisions of the FEJA that improved the constructive regulatory framework of its electric distribution business. The FEJA decoupled electric distribution revenues established in a rate proceeding from actual sales volumes. It provided that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes that are reflected in that year’s rates be collected from, or refunded to, customers within two years. Also, since June 2017, the FEJA has allowed Ameren Illinois towill defer the costs of its electric energy-efficiency programmaintenance expenses incurred related to a refueling and maintenance outage as a regulatory asset and earn a return onamortize those investments. The regulatory asset earns a return at the company’s weighted-average cost of capital, with the equity return based on the monthly average yieldexpenses after completion of the 30-year United States Treasury bonds plus 580 basis points. The equity portionoutage. Maintenance expenses will be amortized over the period between refueling and maintenance outages, which is approximately 18 months. Deferring and amortizing refueling maintenance
expenses allows the timing of expense recognition to more closely align with revenues and mitigates future earnings volatility between outage and non-outage years.
In December 2019, the ICC issued an order that approved a $7 million decrease in Ameren Illinois’ return on electric distribution service rates beginning in January 2020. In November 2019, the ICC issued an order that approved Ameren Illinois’ 2020 electric customer energy-efficiency program investments can also be increased or decreased by up to 200 basis points, depending on the achievementrates of annual energy savings goals. $44 million, which represents an increase of $10 million from 2019 rates.
In January 2018,February 2020, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49$102 million, which included an estimated $42$46 million of annual revenues that would otherwise be recovered under athe QIP riderand other riders. The request wasis based on a 10.3% return on common equity,10.5% allowed ROE, a capital structure composed of 50%54.1% common equity, and a rate base of $1.6$2.1 billion. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information regarding Ameren Illinois’ natural gas delivery service regulatory rate review.
In November 2019, the third quarterFERC issued an order addressing two customer complaint cases filed in November 2013 and February 2015, respectively. The complaint cases were seeking a reduction in the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff of 2017, ATXI finalized an alternative project route12.38%. The order set the allowed base ROE at 9.88% and reached agreementsrequired refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. In December 2019, Ameren and the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and an electric cooperative in northeast Missouri to locate almost allATXI, as well as numerous other parties, filed requests for rehearing with the FERC. The FERC has not ruled on the merits of the rehearing requests and is under no deadline to do so. As of December 31, 2019, Ameren and Ameren Illinois had recorded current liabilities of $40 million and $23 million, respectively, to reflect the expected refunds, including interest. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information regarding the FERC complaint cases.
ATXI continues to make progress with construction activities for its MISO-approved multi-value projects. The Mark Twain project, on existinglocated in northern Missouri, was completed and placed in service in December 2019. Construction of the Illinois Rivers project is substantially complete and eight of its nine line corridors. It also received assents for road crossings fromsegments have been completed and placed in service, with the five affected countieslast section expected to be completed in northeast Missouri. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to begin construction in the second quarter of 2018 and to complete the project by the end of 2019.2020.
In October 2017,2019, Ameren’s board of directors increased the quarterly common stock dividend to 45.7549.5 cents per share, resulting in an annualized equivalent dividend rate of $1.83$1.98 per share.
Earnings
Net income attributable to Ameren common shareholders from continuing operations was $523$828 million, or $2.14$3.35 per diluted share, for 2017,2019, and $653$815 million, or $2.68$3.32 per diluted share, for 2016.2018. Net income was unfavorablyfavorably affected in 2017,2019, compared with 2016,2018, by increased investments in infrastructure at the Ameren Transmission and Ameren Illinois Electric Distribution segments, each of which benefits from formulaic ratemaking, and by the recognition of MEEIA performance incentives. Earnings were also favorably affected in 2019, compared with 2018, by charitable donations returning to more normal levels and lower income tax expense, due toprimarily because of the absence of a noncash charge to earnings for the revaluation of deferred taxes primarily at Ameren (parent) as a result ofrecorded in 2018 related to the TCJA and the increaseincreased tax benefits related to stock-based compensation. Net income was unfavorably affected in the2019, compared with 2018, by milder summer temperatures and higher property taxes, both at Ameren Missouri, and by higher depreciation and amortization expenses at Ameren Illinois income tax rate.Natural Gas and Ameren Missouri. Earnings were also unfavorably affected in 2017,2019, compared with 2016,2018, by decreased demand, primarilya lower recognized ROE at Ameren Missouri, due to milder temperatures in 2017, by the absence in 2017 of the MEEIA 2013 performance incentive, and by increased depreciation and amortization expenses at Ameren Missouri. Net income was favorably affected in 2017, compared with 2016, by an increase in base rates, and lower base level of expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order, and by increased investments in infrastructure at the Ameren Illinois Electric Distribution and Ameren Transmission segments, which reflect Ameren’s strategy to allocate incremental capital to those businesses.
After the application of jurisdictional regulatory recovery mechanisms, the effect of the revaluation of deferred taxes as a result of the TCJA was a decrease to Ameren’s and Ameren Missouri’s net income of $154 million and $36 million, respectively, while the effect on Ameren Illinois’ net income was immaterial.Distribution.
Liquidity
At December 31, 2017,2019, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.6$1.9 billion. In December 2019, the Credit Agreements were extended and now mature in December 2024.
Capital Expenditures
In 2017, Ameren continued to make significantremains focused on strategic capital allocation. We believe we have constructive regulatory frameworks for investment in itsat all of our utility businesses by makingand invested $2.4 billion in those businesses in 2019. The following chart presents 2019 capital expenditures by segment and the midpoint of $0.8 billion, $0.5 billion, $0.2 billion, and $0.6 billion in Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. projected cumulative capital expenditures for 2020 through 2024 by segment:
|
| | | | | | |
2019 Capital Expenditures by Segment (in billions) | | 2020 – 2024 Projected Capital Expenditures by Segment (in billions) |
| | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | |
| | | | | | |
| | Ameren Illinois Electric Distribution | | | Ameren Transmission | |
For 20182020 through 2022,2024, Ameren’s cumulative capital expenditures are projected to range from $10.5$15.4 billion to $11.4$16.6 billion. The following table presents the range of projected spending by segment includes up to $4.5 billion, $2.5 billion, $1.7 billion, and $2.7 billion for Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively.segment:
|
| | | | | | | | |
| | | Range (in billions) |
| Ameren Missouri | | $ | 7.8 |
| – | $ | 8.4 |
|
| Ameren Illinois Electric Distribution | | 2.8 |
| – | 3.0 |
|
| Ameren Illinois Natural Gas | | 1.7 |
| – | 1.8 |
|
| Ameren Transmission | | 3.1 |
| – | 3.4 |
|
| Ameren | | $ | 15.4 |
| – | $ | 16.6 |
|
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Economic conditions, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by nuclear refueling and other energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing, and our pension and postretirement benefits costs. Almost all of Ameren’s revenues are subject to state or federal regulation.
This regulation has a material impact on the pricesrates we charge customers for our services. Customer rates are determined under various regulatory mechanisms. See Note 2 – Rate and Regulatory Matters for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory mechanisms. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, within the frameworks established by our regulators.
Ameren Missouri principally uses coal nuclear fuel, and natural gasenriched uranium for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, and many other factors. As described below, weWe have natural gas cost
recovery mechanisms for our Illinois and Missouri natural gas distribution service businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution service business, and a FAC for Ameren Missouri’s electric utility business.
Ameren Missouri’s FAC cost recovery mechanism allows it 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, with the remaining 5% of changes retained by Ameren Missouri. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense to reduce the previously recognized FAC regulatory asset. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional rate proceeding. Ameren Missouri also has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, 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 costs included in customer rates as a regulatory asset or regulatory liability. The difference will be reflected in base rates in a subsequent MoPSC rate order.
Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers. The FEJA also provides Ameren Illinois with cost recovery of renewable energy credit compliance, zero-emission credits, and energy-efficiency investments as well as a return on those electric energy-efficiency investments. Ameren Illinois’ natural gas business has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through costs do not affect Ameren Illinois’ electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expense and costs of certain asbestos-related claims not recovered in base rates. Ameren Illinois’ natural gas business also has the QIP rider, which provides for recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews.
Ameren Illinois’ electric distribution service rates are reconciled annually to its actual revenue requirement and allowed return on equity, under a formula ratemaking process effective through 2022. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is then collected from, or refunded to, customers within two years.
Ameren Illinois’ electric distribution service revenue requirement is based on recoverable costs, year-end rate base, a capital structure of 50% common equity, and a return on equity. The return on equity component under the IEIMA and the FEJA is equal to the calendar year average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworks for both its electric distribution service and its electric energy-efficiency investments is directly correlated to the yields on such bonds. Beginning in 2017, the FEJA also provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes.
FERC’s electric transmission formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed return on equity. Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These rates are updated each January with forecasted information. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is collected from, or refunded to, customers within two years. The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of Ameren Missouri’s energy centers and our transmission and distribution systems and the level and timing of operations and maintenance costs and capital investment are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.
Earnings Summary
The following table presents a summary of Ameren’s earnings for the years ended December 31, 2017, 2016,2019 and 2015:2018:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Net income attributable to Ameren common shareholders | $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| Earnings per common share – diluted | 2.14 |
| | 2.68 |
| | 2.59 |
|
| Net income attributable to Ameren common shareholders – continuing operations | 523 |
| | 653 |
| | 579 |
|
| Earnings per common share – diluted – continuing operations | 2.14 |
| | 2.68 |
| | 2.38 |
|
2017 versus 2016 |
| | | | | | | |
| | 2019 | | 2018 |
| Net income attributable to Ameren common shareholders | $ | 828 |
| | $ | 815 |
|
| Earnings per common share – diluted | 3.35 |
| | 3.32 |
|
Net income attributable to Ameren common shareholders from continuing operations in 2017 decreased $1302019 increased $13 million, or $0.54$0.03 per diluted share, from 2016.2018. The decreaseincrease was due to an increase innet income increases of $21 million, $14 million, and $10 million, at Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Illinois Electric Distribution, respectively. Additionally, the net loss of $125 million for activity not reported as part of a segment, primarily at Ameren (parent), and adecreased $20 million. The increases in net income were largely offset by a decrease in net income of $34$52 million at Ameren Missouri, both of whichMissouri.
Earnings per share in 2019, compared with 2018, were primarily due to the enactment of the TCJA. The decrease was partially offset by a $23 million and a $5 million increase in net income fromfavorably affected by:
increased Ameren Transmission and Ameren Illinois Electric Distribution respectively.
Compared with 2016, 2017 earnings per share from continuing operations were unfavorably affected by:
an increase in income tax expense,under formula ratemaking, primarily at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decreaseadditional rate base investment and Ameren Illinois Electric Distribution energy-efficiency investments (14 cents per share);
decreased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, excluding the Callaway Energy Center’s scheduled refueling and maintenance outage costs, primarily because of changes in the federal statutory corporate income tax rate resulting from enactmentcash surrender value of the TCJA (63company-owned life insurance (10 cents per share), and an increase in the Illinois corporate;
increased other income, tax rate (6 cents per share), as discussed in Note 12 – Income Taxes under Part II, Item 8, of this report;
decreased demandnet, primarily because charitable donations returned to more normal levels at Ameren Missouri due to milder winter and summer temperatures in 2017 (estimated at 15Ameren (parent), and increased non-service cost components of net periodic benefit income (9 cents per share);
the recognition of MEEIA 2013 and MEEIA 2016 performance incentives (8 cents per share);
the absence in 2017 of a MEEIA 2013 performance incentivenoncash charge to earnings for the revaluation of deferred taxes recorded in 2018 related to the TCJA (5 cents per share);
a decrease in the effective income tax rate at Ameren (parent), primarily because of an increase in the income tax benefit related to stock-based compensation (5 cents per share);
an increase in base rates at Ameren Illinois Natural Gas pursuant to the ICC’s November 2018 natural gas rate order (2 cents per share);
decreased net financing costs at Ameren Missouri, recognizedprimarily as a result of the regulatory deferral of interest expense pursuant to the PISA and lower interest rates, partially offset by lower levels of the allowance for funds used during construction (2 cents per share);
increased Ameren Transmission earnings resulting from the net impact of the November 2019 FERC order addressing the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff (2 cents per share); and
increased Ameren Illinois Natural Gas earnings under the QIP rider resulting from investments in 2016 (7qualifying infrastructure (1 cent per share).
Earnings per share in 2019, compared with 2018, were unfavorably affected by:
decreased electric retail sales at Ameren Missouri, primarily because of milder summer temperatures experienced in 2019 (estimated at 26 cents per share);
increased other operation and maintenance expenses related to the Callaway Energy Center’s scheduled refueling and maintenance outage that was completed in May 2019, as compared with no refueling and maintenance outage in 2018 (9 cents per share);
increased taxes other than income taxes at Ameren Missouri due to higher property taxes (5 cents per share);
increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Illinois Natural Gas and Ameren Missouri, resulting fromprimarily because of additional electric property, plant, and equipment (6 cents per share); and
increased transmission services charges at Ameren Missouri resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities (2 cents per share).
Compared with 2016, 2017 earnings per share from continuing operations were favorably affected by:
an increase in base rates, net of increased revenues in 2016 from the suspension of operations at the New Madrid Smelter, and lower base level of expenses at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report (32 cents per share);
increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base, partially offset by a lower recognized return on equity (9 cents per share);
increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment as well as a higher recognized return on equity (4 cents per share); and
decreased income tax expense, excluding the effect of corporate income tax rate changes discussed above, primarily at Ameren (parent) resulting from changes in the valuation allowance for charitable contributions, tax benefits related to company-owned life insurance, and tax credits in 2017, partially offset by a lower income tax benefit in 2017 related to share-based compensation compared with 2016 (1 cent per share).
The cents per share information presented above is based on the diluted average shares outstanding in 2016. Pretax amounts have been presented net of income taxes, using Ameren’s 2016 statutory tax rate of 39%.
2016 versus 2015
Net income attributable to Ameren common shareholders from continuing operations in 2016 increased $74 million, or $0.30 per diluted share, from 2015. The increase was due to net income increases of $34 million, $22 million, $5 million, and $3 million at Ameren Transmission, Ameren Illinois Natural Gas, Ameren Missouri, and Ameren Illinois Electric Distribution, respectively. Additionally, the net loss from other businesses, primarily Ameren (parent), and intersegment eliminations decreased $10 million.
In 2015, net income attributable to Ameren common shareholders from discontinued operations was favorably affected by the recognition of a tax benefit resulting from the removal of a reserve for unrecognized tax benefits of $53 million recorded in 2013 related to the divestiture of New AER, based on the completion of the IRS audit of Ameren’s 2013 tax year.
Compared with 2015, 2016 earnings per share from continuing operations were favorably affected by:
increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment. Ameren Transmission earnings also benefited from a temporarily higher allowed return on common equity, recognizing an allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 complaint case (19 cents per share);
the absence of a provision recognized in 2015, as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its Callaway energy center site (18 cents per share);
increased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures (estimated at 15 cents per share);
higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order (11 cents per share);
an income tax benefit recorded at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation (9 cents per share);
decreased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri (7 cents per share). This was due, in part, to a reduction in energy center maintenance costs, excluding the cost of the Callaway energy center’s scheduled refueling and maintenance outage (discussed below), and reduced electric distribution maintenance expenditures; and
increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment, partially offset by a lower return on equity resulting from a reduction in the 30-year United States Treasury bond yields (2 cents per share).
Compared with 2015, 2016 earnings per share from continuing operations were unfavorably affected by:
the absence in 2016 of MEEIA net shared benefits due to the expiration of MEEIA 2013, partially offset by the recognition of a MEEIA 2013 performance incentive (15 cents per share);
decreased Ameren Missouri sales to the New Madrid Smelter resulting from a reduction in operations at the smelter (15 cents per share);
the cost of the Callaway energy center’s scheduled refueling and maintenance outage in 2016. There was no Callaway refueling and maintenance outage in 2015 (7 cents per share);
increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri, primarily resulting from additional electric property, plant, and equipment (4(5 cents per share);
decreased Ameren Illinois Electric Distribution earnings resulting from the absence in 2016under formula ratemaking because of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanismlower recognized ROE (4 cents per share);
decreasedincreased transmission services charges at Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues (3 cents per share); and
increased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Illinois Natural Gas, primarily due to increased repairs and compliance expenditures (2weighted-average basic common shares outstanding (3 cents per share).
The cents per share information presented above is based on the diluted averageweighted-average basic shares outstanding in 2015. Pretax amounts2018 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 20152018 statutory tax rate of 39%27%.
For additional details regarding the Ameren Companies’ segment results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Provision for Callaway Construction and Operating License, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income, and Expenses,Net, Interest Charges, Income Taxes, and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.
Below is Ameren’s table of income statement components by segment for the years ended December 31, 2017, 2016,2019 and 2015:2018:
| | | 2017 | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other / Intersegment Eliminations | | Total | |
| 2019 | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other / Intersegment Eliminations | | Ameren |
| Electric margins | $ | 2,431 |
| | $ | 1,109 |
| | $ | — |
| | $ | 426 |
| | $ | (31 | ) | | $ | 3,935 |
| $ | 2,381 |
| | $ | 1,074 |
| | $ | — |
| | $ | 464 |
| | $ | (29 | ) | | $ | 3,890 |
|
| Natural gas margins | 79 |
| | — |
| | 479 |
| | — |
| | (2 | ) | | 556 |
| 81 |
| | — |
| | 519 |
| | — |
| | (2 | ) | | 598 |
|
| Other revenues | — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | — |
| |
| Other operations and maintenance | (902 | ) | | (512 | ) | | (224 | ) | | (63 | ) | | 41 |
| | (1,660 | ) | |
| Other operations and maintenance expenses | | (960 | ) | | (498 | ) | | (233 | ) | | (60 | ) | | 6 |
| | (1,745 | ) |
| Depreciation and amortization | (533 | ) | | (239 | ) | | (59 | ) | | (60 | ) | | (5 | ) | | (896 | ) | (556 | ) | | (273 | ) | | (78 | ) | | (84 | ) | | (4 | ) | | (995 | ) |
| Taxes other than income taxes | (328 | ) | | (74 | ) | | (60 | ) | | (6 | ) | | (9 | ) | | (477 | ) | (329 | ) | | (73 | ) | | (67 | ) | | (4 | ) | | (8 | ) | | (481 | ) |
| Other income and (expenses) | 40 |
| | 3 |
| | (3 | ) | | 1 |
| | (3 | ) | | 38 |
| |
| Other income, net | | 58 |
| | 33 |
| | 12 |
| | 8 |
| | 19 |
| | 130 |
|
| Interest charges | (207 | ) | | (73 | ) | | (36 | ) | | (67 | ) | | (8 | ) | | (391 | ) | (178 | ) | | (71 | ) | | (38 | ) | | (74 | ) | | (20 | ) | | (381 | ) |
| Income taxes | (254 | ) | | (83 | ) | | (36 | ) | | (90 | ) | | (113 | ) | | (576 | ) | |
| Income (taxes) benefit | | (68 | ) | | (45 | ) | | (30 | ) | | (64 | ) | | 25 |
| | (182 | ) |
| Net income (loss) | 326 |
| | 132 |
| | 61 |
| | 141 |
| | (131 | ) |
| 529 |
| 429 |
| | 147 |
| | 85 |
| | 186 |
| | (13 | ) |
| 834 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | $ | 323 |
| | $ | 131 |
| | $ | 60 |
| | $ | 140 |
| | $ | (131 | ) | | $ | 523 |
| $ | 426 |
| | $ | 146 |
| | $ | 84 |
| | $ | 185 |
| | $ | (13 | ) | | $ | 828 |
|
| 2016 | | | | | | | | | | | | |
| 2018 | | | | | | | | | | | | |
| Electric margins | $ | 2,397 |
| | $ | 1,105 |
| | $ | — |
| | $ | 355 |
| | $ | (27 | ) | | $ | 3,830 |
| $ | 2,518 |
| | $ | 1,065 |
| | $ | — |
| | $ | 433 |
| | $ | (27 | ) | | $ | 3,989 |
|
| Natural gas margins | 79 |
| | — |
| | 462 |
| | — |
| | (2 | ) | | 539 |
| 82 |
| | — |
| | 497 |
| | — |
| | (1 | ) | | 578 |
|
| Other revenues | 1 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| |
| Other operations and maintenance | (893 | ) | | (538 | ) | | (215 | ) | | (60 | ) | | 30 |
| | (1,676 | ) | |
| Other operations and maintenance expenses | | (972 | ) | | (506 | ) | | (241 | ) | | (63 | ) | | 10 |
| | (1,772 | ) |
| Depreciation and amortization | (514 | ) | | (226 | ) | | (55 | ) | | (43 | ) | | (7 | ) | | (845 | ) | (550 | ) | | (259 | ) | | (65 | ) | | (77 | ) | | (4 | ) | | (955 | ) |
| Taxes other than income taxes | (325 | ) | | (72 | ) | | (58 | ) | | (4 | ) | | (8 | ) | | (467 | ) | (329 | ) | | (75 | ) | | (66 | ) | | (4 | ) | | (9 | ) | | (483 | ) |
| Other income and (expenses) | 42 |
| | 8 |
| | (1 | ) | | 2 |
| | (9 | ) | | 42 |
| |
| Other income, net | | 56 |
| | 26 |
| | 9 |
| | 7 |
| | 4 |
| | 102 |
|
| Interest charges | (211 | ) | | (72 | ) | | (34 | ) | | (58 | ) | | (7 | ) | | (382 | ) | (200 | ) | | (73 | ) | | (38 | ) | | (75 | ) | | (15 | ) | | (401 | ) |
| Income taxes | (216 | ) | | (78 | ) | | (39 | ) | | (74 | ) | | 25 |
| | (382 | ) | |
| Income (taxes) benefit | | (124 | ) | | (41 | ) | | (25 | ) | | (56 | ) | | 9 |
| | (237 | ) |
| Net income (loss) | 360 |
|
| 127 |
| | 60 |
| | 118 |
| | (6 | ) | | 659 |
| 481 |
|
| 137 |
| | 71 |
| | 165 |
| | (33 | ) | | 821 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | $ | 357 |
| | $ | 126 |
| | $ | 59 |
| | $ | 117 |
| | $ | (6 | ) |
| $ | 653 |
| $ | 478 |
| | $ | 136 |
| | $ | 70 |
| | $ | 164 |
| | $ | (33 | ) |
| $ | 815 |
|
| 2015 | | | | | | | | | | | | |
| Electric margins | $ | 2,481 |
| | $ | 1,074 |
| | $ | — |
| | $ | 259 |
| | $ | (26 | ) | | $ | 3,788 |
| |
| Natural gas margins | 80 |
| | — |
| | 425 |
| | — |
| | (2 | ) | | 503 |
| |
| Other revenues | 2 |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| |
| Other operations and maintenance | (925 | ) | | (532 | ) | | (219 | ) | | (56 | ) | | 38 |
| | (1,694 | ) | |
| Provision for Callaway construction and operating license | (69 | ) | | — |
| | — |
| | — |
| | — |
| | (69 | ) | |
| Depreciation and amortization | (492 | ) | | (212 | ) | | (52 | ) | | (33 | ) | | (7 | ) | | (796 | ) | |
| Taxes other than income taxes | (335 | ) | | (72 | ) | | (56 | ) | | (2 | ) | | (8 | ) | | (473 | ) | |
| Other income and (expenses) | 41 |
| | 8 |
| | (1 | ) | | 2 |
| | (6 | ) | | 44 |
| |
| Interest charges | (219 | ) | | (71 | ) | | (35 | ) | | (35 | ) | | 5 |
| | (355 | ) | |
| Income taxes | (209 | ) | | (71 | ) | | (24 | ) | | (51 | ) | | (8 | ) | | (363 | ) | |
| Income (loss) from continuing operations | 355 |
| | 124 |
| | 38 |
| | 84 |
| | (16 | ) |
| 585 |
| |
| Income from discontinued operations, net of taxes | — |
| | — |
| | — |
| | — |
| | 51 |
| | 51 |
| |
| Net income | 355 |
| | 124 |
| | 38 |
| | 84 |
| | 35 |
| | 636 |
| |
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) | |
| Net income attributable to Ameren common shareholders | $ | 352 |
| | $ | 123 |
| | $ | 37 |
| | $ | 83 |
| | $ | 35 |
|
| $ | 630 |
| |
Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2017, 2016,2019 and 2015:2018: | | | 2017 | Electric Distribution | | Natural Gas | | Transmission | | Total | |
| 2019 | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois |
| Electric margins | $ | 1,109 |
| | $ | — |
| | $ | 258 |
| | $ | 1,367 |
| $ | 1,074 |
| | $ | — |
| | $ | 288 |
| | $ | 1,362 |
|
| Natural gas margins | — |
| | 479 |
| | — | | 479 |
| — |
| | 519 |
| | — |
| | 519 |
|
| Other revenues | 1 |
| | — |
| | — | | 1 |
| |
| Other operations and maintenance | (512 | ) | | (224 | ) | | (53 | ) | | (789 | ) | |
| Other operations and maintenance expenses | | (498 | ) | | (233 | ) | | (51 | ) | | (782 | ) |
| Depreciation and amortization | (239 | ) | | (59 | ) | | (43 | ) | | (341 | ) | (273 | ) | | (78 | ) | | (55 | ) | | (406 | ) |
| Taxes other than income taxes | (74 | ) | | (60 | ) | | (3 | ) | | (137 | ) | (73 | ) | | (67 | ) | | (3 | ) | | (143 | ) |
| Other income and (expenses) | 3 |
| | (3 | ) | | 1 |
| | 1 |
| |
| Other income, net | | 33 |
| | 12 |
| | 8 |
| | 53 |
|
| Interest charges | (73 | ) | | (36 | ) | | (35 | ) | | (144 | ) | (71 | ) | | (38 | ) | | (38 | ) | | (147 | ) |
| Income taxes | (83 | ) | | (36 | ) | | (47 | ) | | (166 | ) | (45 | ) | | (30 | ) | | (35 | ) | | (110 | ) |
| Net income | 132 |
| | 61 |
| | 78 |
| | 271 |
| 147 |
| | 85 |
| | 114 |
| | 346 |
|
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | $ | 131 |
| | $ | 60 |
| | $ | 77 |
| | $ | 268 |
| $ | 146 |
| | $ | 84 |
| | $ | 113 |
| | $ | 343 |
|
| 2016 | | | | | | | | |
| 2018 | | | | | | | | |
| Electric margins | $ | 1,105 |
| | $ | — |
| | $ | 232 |
| | $ | 1,337 |
| $ | 1,065 |
| | $ | — |
| | $ | 267 |
| | $ | 1,332 |
|
| Natural gas margins | — | | 462 |
| | — | | 462 |
| — |
| | 497 |
| | — |
| | 497 |
|
| Other operations and maintenance | (538 | ) | | (215 | ) | | (51 | ) | | (804 | ) | |
| Other operations and maintenance expenses | | (506 | ) | | (241 | ) | | (52 | ) | | (799 | ) |
| Depreciation and amortization | (226 | ) | | (55 | ) | | (38 | ) | | (319 | ) | (259 | ) | | (65 | ) | | (50 | ) | | (374 | ) |
| Taxes other than income taxes | (72 | ) | | (58 | ) | | (2 | ) | | (132 | ) | (75 | ) | | (66 | ) | | (3 | ) | | (144 | ) |
| Other income and (expenses) | 8 |
| | (1 | ) | | 2 |
| | 9 |
| |
| Other income, net | | 26 |
| | 9 |
| | 7 |
| | 42 |
|
| Interest charges | (72 | ) | | (34 | ) | | (34 | ) | | (140 | ) | (73 | ) | | (38 | ) | | (38 | ) | | (149 | ) |
| Income taxes | (78 | ) | | (39 | ) | | (41 | ) | | (158 | ) | (41 | ) | | (25 | ) | | (32 | ) | | (98 | ) |
| Net income | 127 |
| | 60 |
| | 68 |
| | 255 |
| 137 |
| | 71 |
| | 99 |
| | 307 |
|
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | $ | 126 |
| | $ | 59 |
| | $ | 67 |
| | $ | 252 |
| $ | 136 |
| | $ | 70 |
| | $ | 98 |
| | $ | 304 |
|
| 2015 | | | | | | | | |
| Electric margins | $ | 1,074 |
| | $ | — |
| | $ | 189 |
| | $ | 1,263 |
| |
| Natural gas margins | — |
| | 425 |
| | — |
| | 425 |
| |
| Other operations and maintenance | (532 | ) | | (219 | ) | | (46 | ) | | (797 | ) | |
| Depreciation and amortization | (212 | ) | | (52 | ) | | (31 | ) | | (295 | ) | |
| Taxes other than income taxes | (72 | ) | | (56 | ) | | (2 | ) | | (130 | ) | |
| Other income and (expenses) | 8 |
| | (1 | ) | | 2 |
| | 9 |
| |
| Interest charges | (71 | ) | | (35 | ) | | (25 | ) | | (131 | ) | |
| Income taxes | (71 | ) | | (24 | ) | | (32 | ) | | (127 | ) | |
| Net income | 124 |
| | 38 |
| | 55 |
| | 217 |
| |
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | |
| Net income attributable to common shareholder | $ | 123 |
| | $ | 37 |
| | $ | 54 |
| | $ | 214 |
| |
Margins
The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2017 compared with 2016, as well as 2016 compared with 2015. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural 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 they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins |
| 2017 versus 2016 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (65 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (70 | ) |
| Base rates (estimate) | 61 |
| | 42 |
| | — |
| | 71 |
| | — |
| | 174 |
|
| Recovery of power restoration efforts provided to other utilities | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | 8 |
|
| Sales volume (excluding the New Madrid Smelter and estimated effect of weather) | (6 | ) | | — |
| | — |
| | — |
| | — |
| | (6 | ) |
| Off-system sales and capacity revenues | 22 |
| | — |
| | — |
| | — |
| | — |
| | 22 |
|
| MEEIA 2013 performance incentive | (28 | ) | | — |
| | — |
| | — |
| | — |
| | (28 | ) |
| Transmission services revenues | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Other | 4 |
| | (1 | ) | | — |
| | — |
| | 5 |
| | 8 |
|
Cost recovery mechanisms – offset in fuel and purchased power(c) | (11 | ) | | 18 |
| | — |
| | — |
| | — |
| | 7 |
|
Other cost recovery mechanisms(d) | 24 |
| | (36 | ) | | — |
| | — |
| | — |
| | (12 | ) |
| Total electric revenue change | $ | 19 |
| | $ | 19 |
| | $ | — |
| | $ | 71 |
| | $ | 5 |
| | $ | 114 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the New Madrid Smelter and estimated effect of weather) | $ | (22 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (22 | ) |
Effect of weather (estimate)(b) | 13 |
| | (1 | ) | | — |
| | — |
| | — |
| | 12 |
|
| Effect of lower net energy costs included in base rates | 39 |
| | — |
| | — |
| | — |
| | — |
| | 39 |
|
| Transmission services charges | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) |
| Other | (10 | ) | | 4 |
| | — |
| | — |
| | (9 | ) | | (15 | ) |
Cost recovery mechanisms – offset in electric revenue(c) | 11 |
| | (18 | ) | | — |
| | — |
| | — |
| | (7 | ) |
| Total fuel and purchased power change | $ | 15 |
| | $ | (15 | ) | | $ | — |
| | $ | — |
| | $ | (9 | ) | | $ | (9 | ) |
| Net change in electric margins | $ | 34 |
| | $ | 4 |
| | $ | — |
| | $ | 71 |
| | $ | (4 | ) | | $ | 105 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
| QIP rider | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Other | — |
| | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
Cost recovery mechanisms – offset in natural gas purchased for resale(c) | 2 |
| | — |
| | (28 | ) | | — |
| | — |
| | (26 | ) |
Other cost recovery mechanisms(d) | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Total natural gas revenue change | $ | (2 | ) | | $ | — |
| | $ | (11 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Cost recovery mechanisms – offset in natural gas revenue(c) | (2 | ) | | — |
| | 28 |
| | — |
| | — |
| | 26 |
|
| Total natural gas purchased for resale change | $ | 2 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 30 |
|
| Net change in natural gas margins | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
Electric Margins
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2016 versus 2015 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 57 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 72 |
|
| Base rates (estimate) | 48 |
| | 38 |
| | — |
| | 102 |
| | — |
| | 188 |
|
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)
| 7 |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| New Madrid Smelter revenues | (129 | ) | | — |
| | — |
| | — |
| | — |
| | (129 | ) |
| Off-system sales and capacity revenues | 153 |
| | — |
| | — |
| | — |
| | — |
| | 153 |
|
| MEEIA 2013 net shared benefits | (85 | ) | | — |
| | — |
| | — |
| | — |
| | (85 | ) |
| MEEIA 2013 performance incentive | 28 |
| | — |
| | — |
| | — |
| | — |
| | 28 |
|
| Transmission services revenues | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Purchased power rider order in 2015 | — |
| | (15 | ) | | — |
| | — |
| | — |
| | (15 | ) |
| Other | (1 | ) | | (1 | ) | | — |
| | (6 | ) | | (21 | ) | | (29 | ) |
Cost recovery mechanisms – offset in fuel and purchased power(c) | (118 | ) | | (22 | ) | | — |
| | — |
| | — |
| | (140 | ) |
Other cost recovery mechanisms(d) | (39 | ) | | 2 |
| | — |
| | — |
| | — |
| | (37 | ) |
| Total electric revenue change | $ | (76 | ) | | $ | 17 |
| | $ | — |
| | $ | 96 |
| | $ | (21 | ) | | $ | 16 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the New Madrid Smelter and estimated effect of weather) | $ | (145 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (145 | ) |
| New Madrid Smelter energy costs | 72 |
| | — |
| | — |
| | — |
| | — |
| | 72 |
|
Effect of weather (estimate)(b) | (9 | ) | | (8 | ) | | — |
| | — |
| | — |
| | (17 | ) |
| Effect of higher net energy costs included in base rates | (34 | ) | | — |
| | — |
| | — |
| | — |
| | (34 | ) |
| Transmission services charges | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) |
| Other | 6 |
| | — |
| | — |
| | — |
| | 20 |
| | 26 |
|
Cost recovery mechanisms – offset in electric revenue(c) | 118 |
| | 22 |
| | — |
| | — |
| | — |
| | 140 |
|
| Total fuel and purchased power change | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | 26 |
|
| Net change in electric margins | $ | (84 | ) | | $ | 31 |
| | $ | — |
| | $ | 96 |
| | $ | (1 | ) | | $ | 42 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (7 | ) | | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
| Base rates (estimate) | — |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
|
| Other | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Cost recovery mechanisms – offset in natural gas purchased for resale(c) | (2 | ) | | — |
| | (76 | ) | | — |
| | — |
| | (78 | ) |
Other cost recovery mechanisms(d) | — |
| | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Total natural gas revenue change | $ | (9 | ) | | $ | — |
| | $ | (29 | ) | | $ | — |
| | $ | — |
| | $ | (38 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 6 |
| | $ | — |
| | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | (4 | ) |
Cost recovery mechanisms – offset in natural gas revenue(c) | 2 |
| | — |
| | 76 |
| | — |
| | — |
| | 78 |
|
| Total natural gas purchased for resale change | $ | 8 |
| | $ | — |
| | $ | 66 |
| | $ | — |
| | $ | — |
| | $ | 74 |
|
| Net change in natural gas margins | $ | (1 | ) | | $ | — |
| | $ | 37 |
| | $ | — |
| | $ | — |
| | $ | 36 |
|
|
| | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Decrease of $99 Million) | |
| |
| (a) | Includes other/intersegment eliminations of $(29) million and $(27) million in 2019and 2018, respectively. |
Natural Gas Margins
|
| | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $20 Million) | |
| |
| (a) | Includes other/intersegment eliminations of $(2) million and $(1) million in 2019and 2018, respectively. |
The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2019, compared with 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins |
| 2019 versus 2018 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (118 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | — |
| | $ | (118 | ) |
Base rates, including the effects of TCJA (estimate)(c) | (39 | ) | | 5 |
| | — |
| | 31 |
| | — |
| | (3 | ) |
| Power restoration efforts provided to other utilities | (11 | ) | | (9 | ) | | — |
| | — |
| | — |
| | (20 | ) |
| Changes in customer usage patterns and sales volumes (excluding the estimated effects of weather and MEEIA) | 5 |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
| Off-system sales and capacity revenues | (140 | ) | | — |
| | — |
| | — |
| | — |
| | (140 | ) |
| MEEIA 2013 and MEEIA 2016 performance incentives | 26 |
| | — |
| | — |
| | — |
| | — |
| | 26 |
|
| Energy-efficiency program investments | — |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
|
| Other | — |
| | — |
| | — |
| | — |
| | (4 | ) | | (4 | ) |
Cost recovery mechanisms – offset in fuel and purchased power(d) | (49 | ) | | (53 | ) | | — |
| | — |
| | — |
| | (102 | ) |
Other cost recovery mechanisms(e) | (16 | ) | | 2 |
| | — |
| | — |
| | — |
| | (14 | ) |
| Total electric revenue change | $ | (342 | ) | | $ | (43 | ) | | $ | — |
| | $ | 31 |
| | $ | (4 | ) | | $ | (358 | ) |
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | 146 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 146 |
|
Effect of weather (estimate)(b) | 21 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
|
| Transmission services charges | (9 | ) | | — |
| | — |
| | — |
| | — |
| | (9 | ) |
| Other | (2 | ) | | (1 | ) | | — |
| | — |
| | 2 |
| | (1 | ) |
Cost recovery mechanisms – offset in electric revenue(d) | 49 |
| | 53 |
| | — |
| | — |
| | — |
| | 102 |
|
| Total fuel and purchased power change | $ | 205 |
| | $ | 52 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 259 |
|
| Net change in electric margins | $ | (137 | ) | | $ | 9 |
| | $ | — |
| | $ | 31 |
| | $ | (2 | ) | | $ | (99 | ) |
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
| Base rates (estimate) | (1 | ) | | — |
| | 8 |
| | — |
| | — |
| | 7 |
|
| QIP rider | — |
| | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Software licensing agreement | — |
| | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Other | 1 |
| | — |
| | 2 |
| | — |
| | (1 | ) | | 2 |
|
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | 1 |
| | — |
| | (40 | ) | | — |
| | — |
| | (39 | ) |
Other cost recovery mechanisms(e) | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Total natural gas revenue change | $ | (4 | ) | | $ | — |
| | $ | (18 | ) | | $ | — |
| | $ | (1 | ) | | $ | (23 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Cost recovery mechanisms – offset in natural gas revenue(d) | (1 | ) | | — |
| | 40 |
| | — |
| | — |
| | 39 |
|
| Total natural gas purchased for resale change | $ | 3 |
| | $ | — |
| | $ | 40 |
| | $ | — |
| | $ | — |
| | $ | 43 |
|
| Net change in natural gas margins | $ | (1 | ) | | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | (1 | ) | | $ | 20 |
|
| |
| (a) | Includes an increase in transmission margins of $26 million and $43$21 million in 2017 and 2016, respectively,2019, compared with 2018, at Ameren Illinois. The 2017 increase in transmission margins at Ameren Illinois is the change in base rates (estimate) of $26 million. The 2016 increase in transmission margins at Ameren Illinois is the sum of the change in base rates (estimate) of $49 million and the change in Other of -$6 million. |
| |
| (b) | Represents the estimated variation resulting primarily from changes in cooling and heating degree-daysdegree days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. |
| |
| (c) | Includes amounts for power supply, renewable energyFor Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment zero-emission credits, transmission services, and purchased natural gas cost recovery mechanisms, as well as FAC recoveries. under formula rates. |
| |
| (d) | Electric and natural gas revenue changes are offset by corresponding changes in fuel, purchased“Fuel,” “Purchased power,” and natural“Natural gas purchased for resale,resale” on the statement of income, resulting in no change to electric and natural gas margins. |
| |
(d)(e) | Includes amounts for bad debt, energy-efficiency programs,Offsetting expense increases or decreases are reflected in “Other operations and environmental remediation cost recovery mechanisms, as well as gross receipts tax revenues. See Other Operationsmaintenance,” “Depreciation and Maintenance Expensesamortization,” or Taxes Other Than Income Taxes in this“Taxes other than income taxes,” within the “Operating Expenses” section forof the related offsetting increase or decrease to expense.statement of income. These items have no overall impact on earnings. |
2017 versus 2016
Ameren
Ameren’s electric margins increased $105 million, or 3%, in 2017 compared with 2016, primarily because of increased margins at Ameren Transmission and Ameren Missouri. Ameren’s natural gas margins increased $17 million, or 3%, in 2017 compared with 2016, because of increased margins at Ameren Illinois Natural Gas.
Ameren Transmission
Ameren Transmission’s margins increased $71 million, or 20%, in 2017 compared with 2016. Margins were favorably affected by increased capital investment, as evidenced by an increase in rate base of 23% in 2017 compared with 2016, as well as higher recoverable costs in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the allowed return on common equity for FERC-regulated transmission rate base.
Ameren Missouri
Ameren Missouri’s electric margins increased $34 million, or 1%, in 2017 compared with 2016. Ameren Missouri’s natural gas margins were comparable between years.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2017 compared with 2016:
Higher electric base rates, effective April 1, 2017, as a result of the March 2017 MoPSC electric rate order, which increased margins by an estimated $100 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$61 million) and the effect of lower net energy costs included in base rates (+$39 million) in the Electric and Natural Gas Margins table above. Higher electric base rates incorporated the effect of the suspension of operations at the New Madrid Smelter.
Increased transmission services revenues due to additional rate base investment, which increased margins by $11 million.
The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts primarily caused by hurricane damage, which increased revenues by $7 million.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2017 compared with 2016:
Summer temperatures were milder in 2017 compared with 2016, as cooling degree-days decreased 10%. The effect of weather decreased margins by an estimated $52 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$65 million) and the effect of weather (estimate) on fuel and purchased power (+$13 million) in the Electric and Natural Gas Margins table above.
The absence of the MEEIA 2013 performance incentive, which decreased margins by $28 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 performance incentive.
Increased transmission services charges resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, which decreased margins by $16 million.
Excluding the effect of reduced sales to the New Madrid Smelter, the estimated effect of weather, and the estimated effects of MEEIA 2016 customer energy-efficiency programs, total retail sales volumes decreased by less than 1%, which decreased revenues by $6 million. Lower sales volumes were due, in part, to the absence of the leap year benefit experienced in 2016, partially offset by growth. While MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, the throughput disincentive recovery ensured that electric margins were not affected.
Ameren Illinois
Ameren Illinois’ electric margins increased $30$99 million, or 2%, in 20172019, compared with 2016, driven by increases in Ameren Illinois Electric Distribution ($4 million) and Ameren Illinois Transmission ($26 million) margins. Ameren Illinois Natural Gas’ margins increased $17 million, or 4%, in 2017 compared with 2016,2018, primarily due to increased QIP rider recoveries, which increased margins by $12 million.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $4 million, or less than 1%, in 2017 compared with 2016. Ameren Illinois Electric Distribution’s margins were favorably affected by an increase in rate basebecause of 6% in 2017 compared with 2016 and a higher return on common equity due to an increase in 30-year United States Treasury bond yields of 29 basis points in 2017 compared with 2016, as well as higher recoverable expenses under formula ratemaking pursuant to the IEIMA, which collectively increased margins by $42 million. Ameren Illinois Electric Distribution’s margins were unfavorably affected by the absence of the impact of warmer-than-normal summer temperatures experienced in 2016, which decreased margins by an estimated $6 million.at Ameren Illinois Electric Distribution revenues were decoupled from sales volumes beginning in 2017. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$5 million) and the effect of weather (estimate) on fuel and purchased power (-$1 million) in the Electric and Natural Gas Margins table above.
Ameren Illinois Transmission
Ameren Illinois Transmission’s margins increased $26 million, or 11%, in 2017 compared with 2016. Margins were favorably affectedMissouri, partially offset by increased capital investment, as evidenced by an increase in rate base of 16% in 2017 compared with 2016, as well as higher recoverable costs
in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.
2016 versus 2015
Ameren
Ameren’s electric margins increased $42 million, or 1%, in 2016 compared with 2015, primarily because of increased margins at Ameren Transmission and Ameren Illinois Electric Distribution, partially offset by decreased margins at Ameren Missouri.as discussed below. Ameren’s natural gas margins increased $36$20 million, or 7%3%, in 2016 compared with 2015,between years primarily because of increased margins at Ameren Illinois Natural Gas.Gas, as discussed below.
Ameren Transmission
Ameren Transmission’s margins increased $96$31 million, or 37%7%, in 20162019, compared with 2015.2018. Margins were favorably affected by increased capital investment, as evidenced by a 42%12% increase in rate base used to calculate the revenue requirement as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.between years.
Ameren Missouri
Ameren Missouri’s electric margins decreased $84$137 million, or 3%5%, in 20162019, compared with 2015.2018. Ameren Missouri’s natural gas margins were comparable between years.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 20162019, compared with 2015:2018:
Summer temperatures were milder as cooling degree days decreased 13%, and winter temperatures were warmer as heating degree days decreased 4%. The suspensionaggregate effect of the New Madrid Smelter operations in the first quarter of 2016, whichweather decreased margins by $57an estimated $97 million. The change in margins due to lower sales to the New Madrid Smelterweather is the sum of New Madrid Smelterthe effect of weather (estimate) on electric revenues (-$129118 million) and New Madrid Smelter energy coststhe effect of weather (estimate) on fuel and purchased power (+$7221 million) in the Electric and Natural Gas Marginstable above. New Madrid Smelter energy costs included
The reduction of customer rates in accordance with the impact of a provisionTCJA provisions in the FAC tariff that, under certain circumstances, allowed Ameren Missouri law, which decreased revenues an estimated $39 million.
Revenues from other cost recovery mechanisms due primarily to retain a portion of the revenues from any off-system sales it made as a result of reduced sales to the New Madrid Smelter.
The expiration of MEEIA 2013,gross receipts taxes, which decreased margins by $57$16 million. The changeSee Taxes Other Than Income Taxes in margins duethis section for the related offsetting decrease in gross receipts tax.
A reduction in power restoration assistance provided to other utilities and the expirationassociated recovery of MEEIA 2013 is the sum of MEEIA 2013 net shared benefits (-$85 million)labor and MEEIA 2013 performance incentive (+$28 million) in the Electric and Natural Gas Marginstable above. Net shared benefits compensated Ameren Missouribenefit costs for lower sales volumes from energy-efficiency-related volume reductions in current and future periods. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 performance incentive.
crews supporting those efforts, which decreased revenues $11 million.Increased transmission services charges resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, which decreased margins by $16$9 million.
The following items had a favorable effect on Ameren Missouri’s electric margins in 20162019, compared with 2015:2018:
Temperatures inThe MEEIA 2013 and 2016 were warmer compared with 2015, as cooling degree-daysperformance incentives, which increased 16%, while heating degree-days decreased 6%. The net effectrevenues $26 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of weatherthis report for information regarding the MEEIA 2013 and MEEIA 2016 performance incentives.
Net energy costs increased margins by an estimated $48 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$57 million) and the effect of weather (estimate) on fuel and purchased power (-$9 million) in the Electric and Natural Gas Margins table above.
Higher electric base rates, effective May 30, 2015,$6 million as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $14 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$48 million) and the change in effect of higher netlower energy costs included(+$146 million), largely offset by a reduction in base ratesoff-system sales revenue (-$34140 million). The decrease in the Electric and Natural Gas Margins table above.
Lower net energy costs as a result of the 5% of changes retained by Ameren Missouri through the FAC, primarily due to higher MISO capacity revenues, which increased margins by $8 million. The change in net energy costs is the sumresult of lower fuel costs and decreased generation volumes, while the changereduction in off-system sales and capacity revenues (+$153 million) and the change in energy costs (excluding the New Madrid Smelter and estimated effect of weather) (-$145 million) in the Electric and Natural Gas Margins table above.
revenue is primarily due to generation facility outages.Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effecteffects of weather total retail sales volumesand MEEIA customer energy-efficiency programs, electric revenues increased by less than 1%, which increased revenues by $7an estimated $5 million, primarily due to an additional day as a result ofincrease in the leap year and growth, partially offset byaverage retail price per kilowatthour due to changes in customer usage patterns. While the carryover effect of MEEIA 2013 on sales volumes and the effect of MEEIA 2016 customer energy-efficiency programs. MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, but the throughput disincentive recovery of lost electric margins ensured that electric margins were not affected.
Ameren Illinois
Ameren Illinois’ electric margins increased $74$30 million, or 6%2%, in 20162019, compared with 2015,2018, driven by increases inincreased margins at Ameren Illinois Transmission (+$21 million) and Ameren Illinois Electric Distribution ($31(+$9 million) and Ameren Illinois Transmission ($43 million) margins.. Ameren Illinois Natural Gas’ margins increased $37$22 million, or 9%4%, in 2016 compared with 2015.between years.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $31$9 million, or 3%1%, in 20162019, compared with 2015.2018. The following items had a favorable effect on Ameren Illinois Electric Distribution’s electric margins:margins between years:
Revenues increased by $38$12 million primarily becausedue to return on increased energy-efficiency program investments (+$2 million) and recovery of an increase inassociated expenses (+$10 million) under formula ratemaking.
Increased margins due to higher rate base of 8%(+$10 million) and higher recoverable costs in 2016 compared with 2015, under formula ratemaking pursuant to the IEIMA. These revenues were reducedexpenses (+$5 million), partially offset by a lower return on equityrecognized ROE (-$10 million) due to a reduction53 basis point decrease in the annual average of the monthly 30-year United States Treasury bond yields which decreased 24 basis points in 2016 compared with 2015.
Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 13%, while heating degree-days decreased 5%.under formula ratemaking. The net effectsum of weatherthese changes collectively increased margins by an estimated $7$5 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$15 million) and the effect of weather (estimate) on fuel and purchased power (-$8 million) in the Electric and Natural Gas Margins table above.
Ameren Illinois Electric Distribution’s margins were unfavorably affected by a reduction in power restoration assistance provided to other utilities and the absence in 2016associated recovery of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage costlabor and its purchased power rider mechanism,benefit costs for crews supporting those efforts, which increased margins by $15decreased revenues $9 million in 2015.2019, compared with 2018.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $37$22 million, or 9%4%, in 20162019, compared with 2015.2018. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins:
Higher natural gas base rates as a result of the November 2018 natural gas rate order, which increased revenues $8 million.
Revenues from QIP recoveries due to additional investment in 2016,qualified natural gas infrastructure, which increased margins by an estimated $42$7 million.
The absence of warmer-than-normal 2015 winter temperatures and the application of the VBA in 2016,A software licensing agreement with Ameren Missouri, which increased margins by $3revenues $5 million. The VBA, which was approved by the ICC in December 2015, eliminated the impact of weather on natural gas marginsSee Note 13 – Related-party Transactions under Software Licensing Agreement for residential and small nonresidential customers in 2016. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (+$13 million) and the effect of weather (estimate) on natural gas purchased for resale (-$10 million) in the Electric and Natural Gas Margins table above.
information regarding this transaction.Ameren Illinois Transmission
Ameren Illinois Transmission’s margins increased $43$21 million, or 23%8%, in 20162019, compared with 2015.2018. Margins were favorably affected by increased capital investment, as evidenced by a 27%17% increase in rate base used to calculate the revenue requirement as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.between years.
Other Operations and Maintenance Expenses
|
| | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Decrease of $27 Million) | |
| |
| (a) | Includes other/intersegment eliminations of $(6) million and $(10) million in 2019and 2018, respectively. |
Ameren
Other operations and maintenance expenses decreased $16were $27 million lower in 20172019, compared with 2016, because of items2018. In addition to changes by segment discussed below, and an increase in intersegment eliminations of $14 million.
Ameren Transmission
Otherother operations and maintenance expenses increased $3$4 million in 2017 compared with 2016,2019 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of an increase in laborincreased costs due to increased wages and staffing additions.for support services.
Ameren MissouriTransmission
OtherThe $3 million decrease in other operations and maintenance expenses were $9 million higher in 20172019, compared with 2016. 2018, was primarily due to an increase in the cash surrender value of company-owned life insurance due to favorable market conditions.
Ameren Missouri
The $12 million decrease in other operations and maintenance expenses in 2019, compared with 2018, was primarily due to the following items:
The cash surrender value of company-owned life insurance increased $19 million, primarily because of favorable market conditions.
Nonnuclear energy center operations and maintenance costs decreased $15 million, primarily because of higher-than-normal scheduled outages and increased routine maintenance work in 2018.
Power restoration assistance provided to other utilities decreased $11 million.
The following items increasedpartially offset the decrease in other operations and maintenance expenses between years:
MEEIA customer energy-efficiency programCallaway Energy Center operations and maintenance costs increased by $22 million.
Labor and benefit costs increased by $11$28 million, due to increased wages, as well as assistance provided to other utilities to aid in storm recovery efforts, primarily caused by hurricane damage.
Energy center maintenance costs, excludingbecause of the refueling and maintenance outage costs at thethat was completed in May 2019. The previous Callaway energy center, increased by $3 million, primarily due to higher coal handling charges.
The following items decreased other operationsEnergy Center refueling and maintenance expenses between years:outage took place in the fourth quarter of 2017.
Employee benefit costs decreased by $21increased $3 million primarily due to a reduction in the base levelbecause of pension and postretirement expenses allowed in rates as a result of the March 2017 MoPSC electric rate order, as well as changes in the market value of company-owned life insurance.
Solar rebate costs decreased by $8 million, primarily as a result of the March 2017 MoPSC electric rate order.higher medical costs.
Ameren Illinois
Other operations and maintenance expenses decreased $15were $17 million lower at Ameren Illinois in 20172019 compared with 2016,2018, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission in 2017 compared with 2016.between 2019 and 2018.
Ameren Illinois Electric Distribution
OtherThe $8 million decrease in other operations and maintenance expenses were $26 million lower in 20172019, compared with 2016,2018, was primarily due to the following items:
Power restoration assistance provided to other utilities decreased $9 million.
The cash surrender value of company-owned life insurance increased $8 million, primarily because of favorable market conditions.
Bad debt costs, which are recoverable through a $47rider, decreased $6 million, primarily because of improved collections experience.
Meter reading costs decreased $4 million, primarily because of increased automated meter deployment.
The following items partially offset the decrease in customerother operations and maintenance expense between years:
Amortization of regulatory assets associated with energy-efficiency program investments increased $8 million.
Environmental remediation costs, which was partially offset by an $11are recoverable through a rider, increased $6 million, increase in environmentalprimarily because of increased remediation costs and a $3 million increase in labor costs resulting from increased wages.efforts.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $9The $8 million higherdecrease in 2017 compared with 2016, primarily because of increased bad debt, customer energy-efficiency, and environmental remediation costs.
2016 versus 2015
Ameren
Other operations and maintenance expenses decreased $18 million in 2016 compared with 2015, as discussed below.
Ameren Transmission
Other operations and maintenance expenses increased $4 million in 2016 compared with 2015, primarily because of an increase in system operations and labor costs.
Ameren Missouri
Other operations and maintenance expenses were $32 million lower in 2016 compared with 2015. The following items decreased other operations and maintenance expenses between years:
MEEIA customer energy-efficiency program costs decreased by $34 million in 2016,2019, compared with 2018, was primarily because of the expiration of MEEIA 2013, partially offset by costs incurred for MEEIA 2016.
Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center discussed below, decreased by $18 million, primarily because of reduced staffing costs and decreased routine maintenance costs, partially offset by higher coal handling charges.
Electric distribution maintenance expenditures decreased by $16 million, primarily relateddue to reduced system repair and vegetation management work.
Employee benefit costs decreased by $15 million, primarily because of a $6 million reductionan increase in the base level of pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order, and lower medical benefit costs, as well as a $4 million decrease due to changes in the marketcash surrender value of company-owned life insurance.
The following items increased other operations and maintenance expenses between years:
Refueling and maintenance outage costs at the Callaway energy center increased by $26 million, primarily because of costs for the 2016 scheduled refueling and maintenance outage. There was no Callaway refueling and maintenance outage in 2015.
Litigation costs increased by $11 million, primarily related to increases in estimated obligations for pending legal claims.
Solar rebate costs increased by $9 million, as a result of the April 2015 MoPSC electric rate order.
Storm-related repair costs increased by $7 million.
Ameren Illinois
Other operations and maintenance expenses increased $7 million in 2016 compared with 2015, as discussed below.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $6 million higher in 2016 compared with 2015. The following items increased other operations and maintenance expenses between years:
Labor costs increased by $6 million, primarily because of staffing additions to meet enhanced standards and goals related to the IEIMA.
Storm-related repair costs increased by $3 million.
Bad debt, customer energy efficiency, and environmental remediation costs increased by $2 million.
Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.
The following items decreased other operations and maintenance expenses between years:
Employee benefit costs decreased by $6 million,insurance, primarily due to lower pensionfavorable market conditions, and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
Electric distribution operations and maintenance expenditures decreased by $3 million,meter reading costs, primarily related to reduced circuit maintenance work, partially offset by increased vegetation management work.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $4 million lower in 2016 compared with 2015. The following items decreased other operations and maintenance expenses between years:
Bad debt, customer energy-efficiency, and environmental remediation costs decreased by $10 million.
Employee benefit costs decreased by $5 million, primarily because of lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
The following items increased other operations and maintenance expenses between years:
Repairs and compliance expenditures increased by $8 million, primarily relateddue to increased pipeline integrity and storage field maintenance.automated meter deployment.
Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.Ameren Illinois TransmissionOther operations and maintenance expenses were $5 million higher in 2016 compared with 2015, primarily because of an increase in system operations and labor costs.
Provision for Callaway Construction and Operating License
Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site in 2015, primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri. As a result of this decision, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision in 2015 for the previously capitalized COL costs.
Depreciation and Amortization
Depreciation |
| | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $40 Million) | |
| |
| (a) | Includes other/intersegment eliminations of $4 million and $4 million in 2019 and 2018, respectively. |
The $40 million, $6 million, and $32 million increase in depreciation and amortization expenses increased $51 million, $19 million, and $22 million in 20172019, compared with 20162018, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, was primarily because of additional property, plant, and equipment across their respective segments.
2016 versus 2015
Depreciation and amortization expenses increased $49 million, $22 million, and $24 million in 2016 compared with 2015 at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because ofdue to additional property, plant, and equipment across their respective segments. Additionally, Ameren Missouri’s depreciation rates increased asand amortization expenses include a resultreduction for the regulatory deferral of depreciation and amortization expenses pursuant to the April 2015 MoPSC electric rate order.PISA of $22 million between years.
Taxes Other Than Income Taxes
|
| | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Decrease of $2 Million) | |
Taxes other than income taxes increased $10 million in 2017 compared with 2016, as discussed below. 
| |
| (a) | Includes $4 million and $4 million at Ameren Transmission in 2019 and 2018, respectively, and other/intersegment eliminations of $8 million and $9 million in 2019and2018, respectively. |
Taxes other than income taxes were comparable atbetween 2019 and 2018. Ameren Transmission.Missouri’s property taxes increased $17 million, primarily because of higher assessed values, which was offset by a $17 million decrease in excise taxes as a result of reduced sales, primarily driven by mild summer temperatures. See Excise Taxes in Note 115 – Summary of Significant Accounting PoliciesSupplemental Information under Part II, Item 8, of this report for additional information.
Taxes other than income taxes increased $3Other Income, Net
|
| | | | |
| Total by Segment | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $28 Million) | |
The $28 million primarily because of higher gross receipts taxes resulting from an increase in electric revenues.
Other Income, net in 2019, compared with 2018, was primarily due to an $11 million decrease in charitable donations at Ameren Illinois
Taxes other thanMissouri and a $10 million decrease in charitable donations at Ameren (parent), which is reflected in “Other/Intersegment Eliminations” above. Charitable donations returned to more normal levels in 2019. Additionally, the non-service cost components of net periodic benefit income taxes increased $9 million, $5 million, primarily because of increased property taxesand $4 million at Ameren Illinois Electric Distribution, for activity not reported as part of a segment (as reflected in “Other/Intersegment Eliminations” above), and at Ameren Illinois Natural Gas. Taxes other than income taxesGas, respectively. These increases were comparable at Ameren Illinois Transmission.
2016 versus 2015
Ameren
Taxes other than income taxes decreased $6partially offset by an $8 million reduction in 2016 compared with 2015, primarily at Ameren Missouri, as discussed below. Taxes other than income taxes were comparable at Ameren Transmission, as well as at Ameren Illinois and its respective segments.
Ameren Missouri
Taxes other than income taxes decreased $10 million, primarily because of decreased gross receipts taxes resulting from lower residential and commercial electric revenues and because of decreased property taxes.
Other Income and Expenses
2017 versus 2016
Ameren
Other income, net of expenses, decreased $4 million in 2017 compared with 2016, primarily due to decreased income at Ameren Illinois Electric Distribution, as discussed below, along with a decrease in the allowance for equity funds used during construction partially offset by decreased donationsat Ameren Missouri, resulting from a lower average equity-to-debt ratio and a lower average balance of construction work in 2017. Other income, net of expenses, was comparable at the remaining Ameren segments.progress. See Note 6 – Other Income, and ExpensesNet under Part II, Item 8, of this report for additional information. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for more information on the non-service cost components of net periodic benefit income.
Other income, net of expenses, decreased $8 million, primarily because of lower interest income associated with a lower IEIMA revenue requirement reconciliation regulatory asset balance at Ameren Illinois Electric Distribution. Other income, net of expenses, was comparable at the remaining Ameren Illinois segments.2016 versus 2015
Other income, net of expenses, was comparable between years at Ameren, Ameren Missouri, Ameren Illinois, and their respective segments.
Interest Charges
|
| | | | |
| Total by Segment | | Increase (Decrease) by Segment | |
| | (Overall Ameren Decrease of $20 Million) | |
Interest
The $20 million decrease in interest charges increased $9 million in 20172019, compared with 2016, as discussed below.
Ameren Transmission
Interest2018, was primarily due to a $22 million reduction in interest charges increased $9 million, primarily because of an increase in average outstanding debt at Ameren IllinoisMissouri, which resulted from increased regulatory deferrals of interest expense pursuant to the PISA of $16 million between years and ATXI.
Ameren Missouri
Interest charges decreased $4 million, primarily because of a decrease in thelower average interest rate ofrates on long-term debt.
Ameren Illinois
Interest charges increased $4 million, primarily because of an increase in average outstanding debt, partially offset by a The decrease in the average interest rate of debt. Interest charges were comparable between years at each of the Ameren Illinois segments.
2016 versus 2015
Ameren
Interest charges increased $27 million in 2016 compared with 2015, because of an approximately $475 million increase in average outstanding debt and an increase in the average interest rate of debt at Ameren (parent). Ameren (parent) issued senior unsecured notes in November 2015 to repay lower-cost short-term debt incurred primarily in connection with the funding of increasing ATXI investments. An increase in the average interest rate of debt at Ameren TransmissionMissouri was partially offset by a decrease$5 million increase for activity not reported as part of a segment, as reflected in the“Other/Intersegment Eliminations” above, primarily due to a higher average interest rate on an increased level of short-term borrowings and an increased level of long-term debt at Ameren Missouri, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.(parent).
Interest charges increased $23 million, because of an increase in ATXI’s and Ameren Illinois’ average outstanding debt and an increase in the average interest rate of debt.
Ameren Missouri
Interest charges decreased $8 million, primarily because of a decrease in average outstanding debt.
Ameren Illinois
Interest charges increased $9 million, primarily at Ameren Illinois Transmission, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.
Ameren Illinois Transmission
Interest charges increased $9 million, primarily because of an increase in Ameren Illinois’ average outstanding debt and a decrease in the allowance for funds used during construction because of a reduction in construction work in progress as more projects were placed in service in 2016.Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2017, 2016, 2019and 2015:2018:
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| Ameren | 52% | (a) | 37% | | 38% | |
| Ameren Missouri | 44% | (b) | 38% | | 37% | |
| Ameren Illinois | 38% | (c) | 38% | | 37% | |
| Ameren Illinois Electric Distribution | 38% | (c) | 38% | | 36% | |
| Ameren Illinois Natural Gas | 38% | (c) | 39% | | 40% | |
| Ameren Illinois Transmission | 37% | (c) | 38% | | 37% | |
| Ameren Transmission | 39% | (c) | 39% | | 38% | |
| |
(a) | The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate increased the effective income tax rate for 2017 by 15 percentage points. |
| |
(b) | The impact of the revaluation of deferred income taxes as a result of the TCJA increased the effective income tax rate for 2017 by 6 percentage points. |
| |
(c) | The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate had no material effect on the effective income tax rate. |
|
| | | | |
| | 2019 | | 2018 | |
| Ameren | 18% | | 22% | |
| Ameren Missouri | 14% | | 20% | |
| Ameren Illinois | 24% | | 24% | |
| Ameren Illinois Electric Distribution | 23% | | 23% | |
| Ameren Illinois Natural Gas | 26% | | 26% | |
| Ameren Illinois Transmission | 24% | | 24% | |
| Ameren Transmission | 25% | | 25% | |
See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois, as well as a discussionIllinois. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding reductions in revenues related to the effect oflower federal statutory corporate income tax rate enacted under the TCJA and the revaluationreturn of excess deferred income taxes in 2017.
2017 versus 2016to customers.
Ameren
The effective income tax rate was higherlower in 20172019 compared with 2016,2018, primarily because of higher amortization of excess deferred income taxes in 2019 as discussed below, along with revaluation of certain deferred taxes due to enactment ofin 2018. Additionally, the TCJA, which decreased the federal statutory corporate incomeeffective tax rate from 35% to 21% for years after 2017. In addition, income tax expense increased due to the revaluationwas lower because of deferred taxes as a result of an increase in the Illinois income tax rate in 2017 and due to a decrease in the recognition oflower tax benefits associated with share-based compensation, resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. These items were partially offset by a reduction in the valuation allowance related to charitable contributions, due to higher-than-expected current-year taxable income.company-owned life insurance in 2018.
Ameren Transmission
The effective income tax rate was comparable between years.
Ameren Missouri
The effective income tax rate was higher,lower in 2019 compared with 2018, primarily because of revaluationa full year of amortization of excess deferred income taxes due to the reduction in the federal statutory corporate income tax rate described above.2019 compared with a partial year in 2018.
Ameren Illinois
The effective tax rate was comparable between years at Ameren Illinois and its respective segments.
2016 versus 2015
Ameren
The effective tax rate was comparable between years. The reduction in the 2016 effective tax rate, as compared with the 2015 effective tax rate, was primarily a result of the recognition of tax benefits associated with share-based compensation resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. This reduction was partially offset by a higher effective tax rate in 2016 as compared with 2015 at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between years at the remaining Ameren segments.
Ameren Illinois
The effective tax rate was comparable between years. The effective tax rate was higher at Ameren Illinois Electric Distribution, primarily because of items detailed below. The effective tax rate was comparable between years at the remaining Ameren Illinois segments.
Ameren Illinois Electric Distribution
The effective tax rate was higher, primarily because of lower tax benefits from certain depreciation differences on property-related items.
Income (Loss) from Discontinued Operations, Net of Taxes
No material activity was recorded associated with discontinued operations in 2017 or 2016. In 2015, based on completion of the IRS audit of Ameren’s 2013 tax year, Ameren recognized a tax benefit of $53 million due to the resolution of an uncertain tax position from discontinued operations. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
LIQUIDITY AND CAPITAL RESOURCES
Collections from our tariff-based gross marginsrevenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash provided by operating activities, we use available cash, borrowingsdrawings under the Credit Agreements,committed credit agreements, commercial paper issuances, money pool borrowings, and/or, in the case of Ameren Missouri and Ameren Illinois, other short-term affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital
contributions from Ameren (parent). The TCJA will benefit customers through lower rates forIn the near term, our services but is not expected to materially affect our earnings. However, ouroperating cash flows and rate base are expectedwill decrease due to be materially affectedthe reduction in the near term. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows.enacted under the TCJA. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021.2020 because of our use of net operating losses and tax credit carryforwards, which we expect to be fully utilized in 2020. Additionally, operating cash flows will be further reduced by lower customer rates, reflectingresulting from the return of excess deferred taxes previously collected from customers over periods ofincome taxes. Over time, determined by our regulators. Thethe decrease in operating cash flows will be offset as a result of the TCJA is expected to be partially offset over timetemporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts once approved by our regulators. We expect rate base amounts to be higher as a result ofresulting from lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers.liabilities. We also expect to make significant capital expenditures over the next five years as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy requirements, environmental compliance, and other improvements. As part of its plan to fund these capital expenditures, beginning in the first quarter of 2018,cash flow requirements, Ameren will useis using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under itsthe DRPlus and employee benefit plans and expects to continue to do so over the next five years. Additionally, we may be requiredthrough at least 2024. Ameren expects these issuances to provide equity funding of about $100 million annually. Ameren also plans to issue incremental debt and/orcommon equity to fund a portion of Ameren Missouri’s wind generation investments through the physical settlement of the forward sale agreement entered into in August 2019 relating to 7.5 million shares of common stock. Additionally, Ameren plans to issue incremental equity of about $150 million annually from 2021 to 2024. For additional information about the forward sale agreement, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. Ameren expects its equity to total capitalization to be about 45% through the period ending December 2024, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.support solid investment-grade credit ratings.
The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments will periodically resultat the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2017, for the Ameren Companies.2019. The working capital deficit as of December 31, 2017,2019, was primarily the result of current maturities of long-term debt and our decision to finance our businesses with lower-cost commercial paper issuances. With the credit capacity available under the Credit Agreements, along with cash and cash equivalents, the Ameren Companies had access to $1.6net available liquidity of $1.9 billion of liquidity at December 31, 2017.2019. See Credit Facility Borrowings and Liquidity below for additional information.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2017, 2016,2019 and 2015:2018:
| | | | Net Cash Provided by (Used in) Operating Activities | | Net Cash Used in Investing Activities | | Net Cash Provided by (Used in) Financing Activities | Net Cash Provided by Operating Activities | | Net Cash Used in Investing Activities | | Net Cash Provided by (Used in) Financing Activities |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | Variance | | 2019 | | 2018 | | Variance | | 2019 | | 2018 | | Variance |
Ameren(a) – continuing operations | $ | 2,104 |
| | $ | 2,124 |
| | $ | 2,035 |
| | $ | (2,205 | ) | | $ | (2,141 | ) | | $ | (1,951 | ) | | $ | 102 |
| | $ | (265 | ) | | $ | 232 |
| |
Ameren(a) – discontinued operations | — |
| | (1 | ) | | (4 | ) | | — |
| | — |
| | (25 | ) | | — |
| | — |
| | — |
| |
| Ameren | | $ | 2,170 |
| | $ | 2,170 |
| | $ | — |
| | $ | (2,435 | ) | | $ | (2,336 | ) | | $ | (99 | ) | | $ | 334 |
| | $ | 205 |
| | $ | 129 |
|
| Ameren Missouri | 1,016 |
| | 1,169 |
| | 1,247 |
| | (685 | ) | | (934 | ) | | (724 | ) | | (331 | ) | | (434 | ) | | (325 | ) | 1,067 |
| | 1,260 |
| | (193 | ) | | (1,095 | ) | | (976 | ) | | (119 | ) | | 59 |
| | (283 | ) | | 342 |
|
| Ameren Illinois | 815 |
| | 803 |
| | 763 |
| | (1,070 | ) | | (918 | ) | | (913 | ) | | 255 |
| | 44 |
| | 220 |
| 962 |
| | 659 |
| | 303 |
| | (1,205 | ) | | (1,248 | ) | | 43 |
| | 288 |
| | 628 |
| | (340 | ) |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustmentrate-adjustment mechanisms, which may be adjusted without a traditional regulatory rate proceeding.review, subject to prudence reviews. Similar regulatory mechanisms exist for certain operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by changes in customer demand due to weather, significantly affect the amount and timing of our cash provided
by operating activities. See Part 1, Item 1, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our rate-adjustmentregulatory mechanisms.
2017 versus 2016
Ameren
Ameren’s cash from operating activities associated with continuing operations decreased $20 millionwas flat in 2017,2019, compared with 2016.2018. The following items contributed to the decrease:
A $48 million decrease inincreased cash related to customer energy-efficiency program recovery mechanisms.
The absence of a $42 million insurance receipt received in 2016 at Ameren Missouri related to the Taum Sauk breach that occurred in December 2005.from operating activities between periods:
A $36 million decrease in cash recoveries associated with Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. The
2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
A $27 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.
A $27 million decrease in cash related to Ameren Illinois’ power procurement cost recovery mechanism.
Refunds paid in 2017 of $21 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
A $17 million decrease in cash associated with Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
A $14 million increase in the cost of natural gas held in storage, caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.
A $13 million increase in interest payments, primarily due to an increase in the average outstanding debt at Ameren Illinois.
A $10 million increase in labor costs at Ameren Missouri and Ameren Illinois, primarily because of wage increases.
A $7 million increase in pension and postretirement benefit plan contributions.
A $4net $15 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and increased natural gas compliance costs.
The following items partially offset the decrease in Ameren’s cashcollateral received from operating activities associated with continuing operations between years:
A $167 million increasecounterparties, primarily resulting from electricchanges in the market prices of power and natural gas, margins, as discussedchanges in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
A $37 million increase in cash collected from Ameren Illinois customers related to zero-emission credits pursuant to the FEJA. In the first quarter of 2018, these funds will be used for the purchase of zero-emission credits pursuant to an IPA procurement event.
A $23 million increase in cash collectedcontracted commodity volumes, and increases resulting from Ameren Illinois’ alternative retail electric supplier customers for renewable energy credit compliancecontracts entered into pursuant to the FEJA.
A $14 million decrease in coal inventory because ofpayments to contractors for electric distribution maintenance costs, primarily due to decreased market prices and decreased purchasesvegetation management costs at Ameren Illinois.
A $13 million decrease in payments related to charitable donations.
An $11 million decrease in property tax payments at Ameren Missouri as a result of inventory reductions at its energy centers.due to lower property tax values.
The following items decreased Ameren’s cash from operating activities associated with discontinued operationsbetween periods:
A $33 million decrease resulting from decreased customer collections, primarily due to a decrease in weather-related sales volumes at Ameren Missouri, and a net decrease attributable to regulatory recovery mechanisms, partially offset by decreased fuel costs and generation volumes at Ameren Missouri and decreased purchase power costs and volumes and natural gas costs at Ameren Illinois.
A $28 million increase in payments for nuclear refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. There was immaterialno refueling and maintenance outage in both 2017 and 2016.2018.
A $14 million decrease resulting from increased Ameren Missouri purchases to maintain coal inventory at near targeted levels.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased $153$193 million in 2017,2019, compared with 2016.2018. The following items contributed to the decrease:
AnA $236 million decrease resulting from decreased customer collections, primarily due to a decrease in weather-related sales volumes, and a net decrease attributable to regulatory recovery mechanisms, partially offset by decreased fuel costs and generation volumes.
A $28 million increase in income tax payments of $151 million to Ameren (parent) pursuant tofor nuclear refueling and maintenance outages at the tax allocation agreement, primarily related to higher taxable incomeCallaway Energy Center. There was no refueling and maintenance outage in 2017, because of significantly lower property-related deductions.
The absence of a $42 million insurance receipt received in 2016 related to the Taum Sauk breach that occurred in December 2005.2018.
A $27$14 million decrease in net energy costs collectedresulting from customers under the FAC.
A $20 million decrease in cash relatedincreased purchases to customer energy-efficiency program recovery mechanisms.maintain coal inventory at near targeted levels.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities between years:periods:
A $70$27 million decrease in income tax payments to Ameren (parent) pursuant to the tax allocation agreement, primarily due to lower taxable income in 2019.
A $15 million decrease in pension and postretirement benefit plan contributions.
A net $11 million increase in collateral received from counterparties, primarily resulting from electricchanges in the market prices of power and natural gas margins, as discussedand in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.contracted commodity volumes.
A $14An $11 million decrease in coal inventory as a result of decreased market prices and decreased purchases as a result of inventory reductions at the energy centers.property tax payments due to lower property tax values.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased $12$303 million in 2017,2019, compared with 2016.2018. The following items contributed to the increase:
A $75$200 million increase primarily resulting from electricdecreased purchased power costs and volumes, decreased natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.costs, and a net increase attributable to regulatory recovery mechanisms.
A $37$24 million increasedecrease in cash collected from customers related to zero-emission credits pursuant to the FEJA. In the first quarter of 2018, these funds will be used for the purchase of zero-emission credits pursuant to an IPA procurement event.
A $30 million increase resulting from income tax refunds of $22 million in 2017, compared with income tax payments of $8 million in 2016,to Ameren (parent) pursuant to the tax allocation agreement, with Ameren (parent), primarily related to a larger taxable loss in 2017 as a result of higher property-related deductions and use of net operating losses.
A $23 million increase in cash collected from alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.
The following items partially offset the increase in Ameren Illinois’ cash from operating activities between periods:
A $36 million decrease in cash recoveries associated with IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
A $28 million decrease in cash related to customer energy-efficiency program recovery mechanisms.
A $27 million decrease in cash related to the power procurement cost recovery mechanism.
A $17 million decrease in cash recoveries associated with the transmission revenue requirement reconciliation adjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
Refunds paid in 2017 of $17 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
A $14 million increase in the cost of natural gas held in storage, caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.
A $13 million increase in interest payments, primarily due to an increase in the average outstanding debt.
2016 versus 2015
Ameren
Ameren’s cash from operating activities associated with continuing operations increased $89 million in 2016, compared with 2015. The following items contributed to the increase:timing of payments.
A $126 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.
A $70$16 million decrease in pension and postretirement benefit plan contributions.
A $42$14 million insurance receipt at Ameren Missouri related to the Taum Sauk breach that occurred in 2005.
A $40 million increase in cash associated with the recovery of Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
A $38 million increase in cash related to Ameren Illinois’ power procurement cost recovery mechanism.
A $37 million decrease in coal inventory purchases at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.
A $33 million increase in cash related to customer energy-efficiency program recovery mechanisms.
A $19 million increase in cash associated with the recovery of Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.
The following items partially offset the increase in Ameren’s cash from operating activities associated with continuing operations during 2016, compared with 2015:
A $166 million decrease resulting from the change in customer receivable balances.
A $94 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.
A $23 million increase in interest payments, primarily due to an increase in the cost and amount of outstanding debt of Ameren (parent) and an increase in the average outstanding debt at Ameren Illinois.
A $20 million increase in payments for the refueling and maintenance outage at Ameren Missouri’s Callaway energy center. There was no refueling and maintenance outage in 2015.
A $9 million increase in labor costs at Ameren Illinois, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.
A $7 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects.
Ameren’s cash from operating activities associated with discontinued operations was immaterial in both 2016 and 2015.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased $78 million in 2016, compared with 2015. The following items contributed to the decrease:
A $142 million decrease resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
A $94 million decrease in net energy costs collected from customers under the FAC.
A $20 million increase in payments for the refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during 2016, compared with 2015:
A $45 million decrease in income tax payments, pursuant to the tax allocation agreement with Ameren (parent), primarily related to higher deductions related to increased capital expenditures in 2016.
A $42 million insurance receipt related to the Taum Sauk breach that occurred in December 2005.
A $37 million decrease in coal inventory purchases, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.
A $33 million decrease in pension and postretirement benefit plan contributions.
An $11 million increase in cash related to customer energy-efficiency program recovery mechanisms.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased $40 million in 2016, compared with 2015. The following items contributed to the increase:
A $58 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, which was partially offset by the change in customer receivable balances.
A $40 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
A $38 million increase in cash related to the power procurement cost recovery mechanism.
A $22 million decrease in pension and postretirement benefit plan contributions.
A $22 million increase in cash related to customer energy-efficiency program recovery mechanisms.
A $19 million increase in cash associated with the recovery of transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.
The following items partially offset the increase in Ameren Illinois’ cash from operating activities during 2016, compared with 2015:
A $121 million decrease resulting from income tax payments of $8 million in 2016, compared with income tax refunds of $113 million in 2015, pursuant to the tax allocation agreement with Ameren (parent). During 2015, Ameren Illinois used net operating loss carryforwards from prior years, resulting in a reduction in payments. Ameren Illinois also had higher deductions for increased capital expenditures in 2015.
A $9 million increase in labor costs primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.
A $7 million increase in payments to contractors for additional reliability,electric distribution maintenance and IEIMA projects.costs, primarily due to decreased vegetation management costs.
A $7net $4 million increase in interest payments,collateral received from counterparties, primarily due to an increaseresulting from changes in the average outstanding debt, including senior secured notes issuedmarket prices of power and natural gas, changes in December 2015.contracted commodity volumes, and increases resulting from renewable energy contracts entered into pursuant to the FEJA.
Pension Plans
Ameren’s pension plans are funded in compliance with income tax regulations, federal funding requirements, and other regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on Ameren’s assumptions at December 31, 2017,2019, its investment performance in 2017,2019, and its pension funding policy, Ameren expects to make annual contributions of less than $1 millionup to $60$45 million in each of the next five years, with aggregate estimated contributions of $120$70 million. We expectestimate that Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements towill be 35%approximately 30% and 55%60%, respectively. These amounts are estimates. Theyestimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In 2017,2019, Ameren contributed $64$23 million to its pension plans. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.
Cash Flows from Investing Activities
2017 versus 2016
Ameren’s cash used in investing activities associated with continuing operations increased by $64$99 million during 2017,2019, compared with 2016. Capital expenditures increased $56 million2018, primarily as a result of activityincreased capital expenditures of $125 million, partially offset by a $21 million decrease due to the timing of nuclear fuel expenditures. In addition to the capital expenditure changes at Ameren Missouri and Ameren Illinois discussed below. The $187 million increase inbelow, ATXI’s capital expenditures at Ameren Missouri and Ameren Illinois was partiallyincreased $38 million. ATXI’s capital expenditures increased as a result of increased expenditures on the Mark Twain project offset by a $127 million decrease indecreased capital expenditures at ATXI due to reduced spending on the Illinois Rivers project, partially offset by an increase in spending on the Spoon River project. During 2017 and 2016, thereThe Mark Twain project was no cash usedplaced in investing activities associated with discontinued operations.
Ameren Missouri’s cash usedservice in investing activities decreased by $249 million during 2017, compared with 2016, primarily because of net money pool advances. During 2017, Ameren Missouri received $161 millionDecember 2019, while the Spoon River project was placed in returns of net money pool advances compared with investing $125 millionservice in net money pool advances in 2016. This decrease was partially offset by a $35 million increase in capital expenditures, primarily related to electric distribution and transmission system reliability and energy center projects.
Ameren Illinois’ cash used in investing activities increased by $152 million during 2017, compared with 2016, because of increased capital expenditures, primarily related to electric transmission system reliability projects and natural gas infrastructure projects.
2016 versus 2015
Ameren’s cash used in investing activities associated with continuing operations increased by $190 million during 2016, compared with 2015. Capital expenditures increased $159 million, primarily because of increased transmission expenditures, which included a $41 million increase at ATXI primarily related to the Illinois Rivers project, and increased Ameren Missouri and Ameren Illinois capital expenditures.
During 2016, there was no cash used in investing activities associated with discontinued operations. During 2015, Ameren’s cash used in investing activities associated with discontinued operations consisted of a $25 million payment for a liability associated with the New AER divestiture.February 2018.
Ameren Missouri’s cash used in investing activities increased by $210$119 million during 2016,2019, compared with 2015. Capital2018, primarily as a result of increased capital expenditures increased $116of $162 million, partially offset by a $21 million decrease due to the timing of nuclear fuel expenditures. Ameren Missouri’s $162 million increase in capital expenditures between periods was primarily related to electric distribution system reliabilityenergy delivery infrastructure upgrades and energy center projects. Additionally, there was an increase in net advances to the money pool of $89 million.substation upgrades.
Ameren Illinois’ cash used in investing activities increased by $5decreased $43 million during 2016,2019, compared with 2015, because2018, due to decreased capital expenditures of increased capital expenditures,$50 million, primarily related to qualified investments in natural gas infrastructure under the QIP rider, storm restoration costs, and reliability.electric transmission system reliability projects.
Capital Expenditures
The following table presents thecharts present our capital expenditures by the Ameren Companies for the years ended December 31, 2017, 2016,2019, and 2015:2018:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 773 |
| | $ | 738 |
| | $ | 622 |
|
| Ameren Illinois Electric Distribution | 476 |
| | 470 |
| | 491 |
|
| Ameren Illinois Natural Gas | 245 |
| | 181 |
| | 133 |
|
| Ameren Illinois Transmission | 355 |
| | 273 |
| | 294 |
|
| ATXI | 289 |
| | 416 |
| | 375 |
|
Other (a) | (6 | ) | | (2 | ) | | 2 |
|
| Ameren | $ | 2,132 |
| | $ | 2,076 |
| | $ | 1,917 |
|
|
| | | | | | |
2019 - Total Ameren $2,411(a) | | 2018 - Total Ameren $2,286(a) |
| | |
| | Ameren Missouri | | | Ameren Illinois Transmission | |
| | | | | | |
| | Ameren Illinois Electric Distribution | | | Ameren Transmission Company of Illinois |
| | | | | | |
| | Ameren Illinois Natural Gas | | | | |
| |
(a) | Includes Other capital expenditures of $(29) million and $(4) million for the years ended December 31, 2019 and 2018, respectively, which includes amounts for the elimination of intercompany transfers. |
Ameren’s 20172019 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $289$156 million primarily on the Mark Twain and Illinois Rivers and Spoon River projects. In 2019, Ameren Illinois spent $355$372 million on transmission projects, $153$203 million on natural gas projects that are recovered under theeligible for QIP rider,recovery, and $123$67 million on IEIMA projects. OtherIn both years, other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects. As of December 31, 2019, Ameren Illinois exceeded the minimum capital spending levels required pursuant to IEIMA.
Ameren’s 20162018 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $416$118 million primarily on the Illinois Rivers project.and Mark Twain projects. In 2018, Ameren Illinois spent $273$444 million on transmission projects, $188 million on natural gas projects eligible for QIP recovery, and $109$89 million on IEIMA projects. Other
capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.
Ameren’s 2015 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $375 million primarily on the Illinois Rivers project. Ameren Illinois spent $294 million on transmission projects and $134 million on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.
The following table presents Ameren’s estimate of capital expenditures that will be incurred from 20182020 through 2022,2024, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations. Ameren expects to continue to allocate more of its capital expenditures to Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission based, in part, on the constructive regulatory frameworks within which they operate.regulations:
| | | | 2018 | | 2019-2022 | | Total | 2020 | | 2021-2024 | | Total |
| Ameren Missouri | $ | 845 |
| | $ | 3,310 |
| - | $ | 3,660 |
| | $ | 4,155 |
| - | $ | 4,505 |
| $ | 2,440 |
| | $ | 5,380 |
| – | $ | 5,945 |
| | $ | 7,820 |
| – | $ | 8,385 |
|
| Ameren Illinois Electric Distribution | 465 |
| | 1,815 |
| - | 2,005 |
| | 2,280 |
| - | 2,470 |
| 550 |
| | 2,245 |
| – | 2,480 |
| | 2,795 |
| – | 3,030 |
|
| Ameren Illinois Natural Gas | 330 |
| | 1,220 |
| - | 1,350 |
| | 1,550 |
| - | 1,680 |
| 345 |
| | 1,310 |
| – | 1,450 |
| | 1,655 |
| – | 1,795 |
|
| Ameren Illinois Transmission | 470 |
| | 1,765 |
| - | 1,950 |
| | 2,235 |
| - | 2,420 |
| 605 |
| | 2,310 |
| – | 2,555 |
| | 2,915 |
| – | 3,160 |
|
| ATXI | 70 |
| | 215 |
| - | 240 |
| | 285 |
| - | 310 |
| 85 |
| | 110 |
| – | 120 |
| | 195 |
| – | 205 |
|
| Other | 5 |
| | 15 |
| - | 15 |
| | 20 |
| - | 20 |
| 5 |
| | 10 |
| – | 10 |
| | 15 |
| – | 15 |
|
| Ameren | $ | 2,185 |
| | $ | 8,340 |
| - | $ | 9,220 |
| | $ | 10,525 |
| - | $ | 11,405 |
| $ | 4,030 |
| | $ | 11,365 |
| – | $ | 12,560 |
| | $ | 15,395 |
| – | $ | 16,590 |
|
Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, as well as expenditures for compliance with environmental regulations. The estimates above do not reflect the potential additional investments identified inIn addition, Ameren Missouri’s integrated resource plan, which could represent incrementalestimated capital
expenditures include approximately $1.2 billion in wind generation investments expected to be acquired by the end of approximately $1 billion through 2020 and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made.2020. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, capital expenditures to modernize its distribution system pursuant to the IEIMA, and capital expenditures for qualified investments in natural gas infrastructure under the QIP rider. ATXI’s estimated capital expenditures include expenditures for the threeIllinois Rivers MISO-approved multi-value transmission projects. For additional information regarding the IEIMA capital expenditure requirements, the QIP rider,project, and ATXI’sconstruction of a transmission projects, see Part I, Item 1, of this report.operating center.
Ameren Missouri continually reviews its generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments.investments within and outside our service territories. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.
Environmental Capital Expenditures
Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO2, NOx, and mercury emissions from its coal-fired energy centers. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws and regulations that affect, or may affect, our facilities and capital expenditures to comply with such laws and regulations.laws.
Cash Flows from Financing Activities
Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the dividends declared by Ameren’s boardlevel of directors,dividends, and our long-term debt maturities, among other things.
2017 versus 2016
Ameren’s financing activities associatedIn 2019, Ameren issued $1,527 million of long-term debt to repay then-outstanding commercial paper borrowings, including short-term debt incurred in connection with continuing operations providedthe repayment at maturity of long-term debt, and to repay at maturity other long-term debt. Collectively, in 2019, Ameren repaid long-term debt of $580 million and net cash of $102 millioncommercial paper borrowings totaling $157 million. In comparison, in 2017, compared with using net cash of $265 million in 2016. During 2017,2018, Ameren utilized net proceeds from the issuance of $1,345$1,352 million of long-term indebtednessdebt, along with cash on-hand, to repay $681then-outstanding commercial paper borrowings, including short-term debt incurred in connection with the repayment at maturity of long-term debt, and to repay at maturity other long-term debt. Collectively, in 2018, Ameren repaid $841 million of higher-cost long-term indebtedness, to repay $74debt and received $112 million offrom net commercial paper issuances,issuances. In 2019 and 2018, Ameren used cash provided by financing activities to fund, in part, investing activities.
In comparison, during 2016,2019, Ameren utilized net proceeds from the issuance of $646Missouri issued $778 million of long-term indebtedness
debt to repay then-outstanding commercial paper borrowings, including short-term debt incurred in connection with the repayment at maturity of long-term debt, and to repay at maturity other long-term debt. Collectively, in 2019, Ameren Missouri repaid long-term debt of $580 million and received $179 million from net commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and to fund,issuances. In comparison, in part, investing activities. Additionally, during 2017, Ameren made $431 million in dividend payments to shareholders, compared with $416 million in dividend payments in 2016. No cash from financing activities was used for discontinued operations during 2017.
Ameren Missouri’s cash used in financing activities decreased by $103 million in 2017, compared with 2016. During 2017,2018, Ameren Missouri utilized net proceeds of $423 million from the issuance of $438 million ofin long-term indebtedness and net commercial paper issuances to repay $431 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds,debt, along with cash on hand, to repay $266then-outstanding commercial paper borrowings, including short-term debt incurred in connection with the repayment at maturity of long-term debt, and to repay at maturity other long-term debt. Collectively, in 2018, Ameren Missouri received $16 million from net commercial paper issuances. Collectively, in 2018, Ameren Missouri repaid $384 million of higher-cost long-term indebtedness. In 2017,debt. During 2019, Ameren Missouri paid $362common stock dividends of $430 million, compared with $375 million in dividends to Ameren (parent), compared with $355 million dividends paiddividend payments in 2016. Additionally,the year-ago period. In addition, during 2017,2019, Ameren Missouri received $30$124 million in capital contributions from Ameren (parent) associated with the tax allocation agreement, compared to $44with $45 million received in 2016.
2018. In 2019, Ameren Illinois’Missouri used cash provided by financing activities increased by $211to fund, in part, investing activities.
In 2019, Ameren Illinois issued $299 million of long-term debt to repay then outstanding commercial paper borrowings. Ameren Illinois repaid outstanding net commercial paper borrowings totaling $19 million. In comparison, in 2017, compared with 2016. During 2017,2018, Ameren Illinois utilized net proceeds of $929 million from the issuance of $507 millionlong-term debt to repay then-outstanding commercial paper borrowings, including short-term debt incurred in connection with the repayment at maturity of long-term indebtednessdebt, and net commercial paper issuances to repay at maturity $250 million of higher-costother long-term indebtedness. In comparison, during 2016,debt. Collectively, in 2018, Ameren Illinois issued $291repaid $457 million of long-term indebtednessdebt and received $10 million from net commercial paper issuances and utilized the proceeds to repay at maturity $129issuances. In addition, during 2019, Ameren Illinois received $15 million of higher-cost long-term indebtedness. Additionally, in 2017, no dividends were paid tocapital contributions from Ameren (parent) associated with the tax allocation agreement, compared to $110with $160 million paidreceived in 2016.
2016 versus 2015
Ameren’s2018. In 2019 and 2018, Ameren Illinois used cash provided by financing activities associated with continuing operations used net cash of $265 million in 2016, compared with providing net cash of $232 million in 2015. During 2016, Ameren utilized net proceeds from the issuance of $646 million of long-term indebtedness and net commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during 2015, Ameren utilized net proceeds from the issuance of $1,197 million of long-term indebtedness to repay $413 million of net commercial paper issuances, $120 million of higher-cost long-term indebtedness, and to fund, in part, investing activities. No cash from financing activities was used for discontinued operations during 2016.
Ameren Missouri’s cash used in financing activities increased by $109 million in 2016, compared with 2015. During 2016, Ameren Missouri utilized net proceeds from the issuance of $149 million of long-term indebtedness, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In comparison, during 2015, Ameren Missouri utilized net proceeds from the issuance of $249 million of long-term indebtedness to repay $120 million of higher-cost long-term indebtedness and $97 million of net commercial paper issuances. Additionally, during 2016, Ameren Missouri paid $355 million in dividends to Ameren (parent), compared with $575 million dividends paid in the year-ago period. Also, in 2016, Ameren Missouri received $44 million as a capital contribution from Ameren (parent) compared to $224 million received in 2015.
Ameren Illinois’ cash provided by financing activities decreased by $176 million in 2016, compared with 2015. During 2016, Ameren Illinois issued $291 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay at maturity $129 million of higher-cost long-term indebtedness. In comparison, during 2015, Ameren Illinois utilized proceeds from the issuance of $248 million of long-term indebtedness to repay $32 million of net commercial paper issuances and to fund, in part, investing activities. Additionally, in 2016 Ameren Illinois paid $110 million in dividends to Ameren (parent) compared to no dividends paid in the year-ago period.
Credit Facility Borrowings and Liquidity
The liquidity needs of the Ameren Ameren Missouri, and Ameren IllinoisCompanies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, or, proceeds fromin the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings, drawings under the Credit Agreements, or commercial paper issuances.borrowings. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, short-term affiliate borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s money pool arrangements.arrangements and related borrowings, and relevant interest rates.
The following table presents Ameren’s consolidated net available liquidity as of December 31, 20172019:
| | | | | Available at December 31, 2017 | | Available at December 31, 2019 |
Ameren (parent) and Ameren Missouri (a): | | | | |
Missouri Credit Agreement – borrowing capacity | | $ | 1,000 |
| | $ | 1,200 |
|
| Less: Ameren (parent) commercial paper outstanding | | 224 |
| | 98 |
|
| Less: Ameren Missouri commercial paper outstanding | | 39 |
| | 234 |
|
Missouri Credit Agreement – credit available | | 737 |
| |
| Less: Letters of credit | | | 2 |
|
Missouri Credit Agreement – subtotal | | | 866 |
|
Ameren (parent) and Ameren Illinois(b): | | | | |
Illinois Credit Agreement – borrowing capacity | | 1,100 |
| | 1,100 |
|
| Less: Ameren (parent) commercial paper outstanding | | 159 |
| | 55 |
|
| Less: Ameren Illinois commercial paper outstanding | | 62 |
| | 53 |
|
| Less: Letters of credit | | 1 |
| | 1 |
|
Illinois Credit Agreement – credit available | | 878 |
| |
| Total Credit Available | | $ | 1,615 |
| |
Illinois Credit Agreement – subtotal | | | 991 |
|
| Subtotal | | | $ | 1,857 |
|
| Cash and cash equivalents | | 10 |
| | 16 |
|
| Total Liquidity | | $ | 1,625 |
| |
| Net Available Liquidity | | | $ | 1,873 |
|
| |
| (a) | The maximum aggregate amount available to Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $700$900 million and $800$850 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements. |
| |
| (b) | The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the Illinois Credit Agreement is $500 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements. |
TheIn December 2019, the Credit Agreements were amended and restated. The amended and restated agreements, among other things, provide $2.1$2.3 billion of credit cumulatively throughuntil maturity in December 2021. The maturity date may be extended2024. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for two additional one-year periods upon mutual consent ofinformation on the borrowersamended and lenders. Borrowings by Ameren (parent) under either of the Credit Agreements are due and payable no later than the maturity date, while borrowings by Ameren Missouri and Ameren Illinois are due and payable no later than the earlier of the maturity date or 364 days after the date of such borrowing (subject to the right of each borrower to re-borrow in accordance with the terms of the applicable Credit Agreement). The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the credit agreements are available to Ameren (parent) to support issuances under Ameren (parent)’s commercial paper program, subject to available credit capacity under therestated agreements. The Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. The Illinois Credit Agreement is available to support issuances under Ameren Illinois’ commercial paper program. Issuances under the Ameren (parent), Ameren Missouri, and Ameren Illinois commercial paper programs were available at lower interest rates than the interest rates of borrowings under the Credit Agreements. Commercial paper issuances were thus preferred to credit facility borrowings as a source of third-party short-term debt.
Ameren has a money pool agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option has the lowest interest rates. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a detailed explanation of the utility money pool arrangement.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval by the FERC under the Federal Power Act. In June 2017, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2019. In 2016,2018, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 20182020 and September 2020, respectively. In July 2019, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through September 2018, respectively.July 2021.
The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements for changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or to other short-term borrowing arrangements.
Long-term Debt and Equity
The following table presents ourAmeren’s equity issuances, as well as issuances (net of issuance premiums or discounts), redemptions, repurchases, and maturities of long-term debt for the years ended December 31, 2017, 2016,2019 and 2015. The Ameren Companies did not issue any common stock or redeem or repurchase any preferred stock during the years ended 2017, 2016, and 2015. In 2017, 2016, and 2015, Ameren Missouri received cash capital contributions as a result of the tax allocation agreement from Ameren (parent). In 2017 and 2015, Ameren Illinois received cash capital contributions from Ameren (parent)2018. For additional information related to the terms and uses of these issuances and effective registration statements, and Ameren’s forward sale agreement relating to common stock, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.
|
| | | | | | | | | | | | | |
| | Month Issued, Redeemed, Repurchased, or Matured | | 2017 | | 2016 | | 2015 |
| Issuances of Long-term Debt | | | | | | | |
| Ameren (parent) | | | | | | | |
| 2.70% Senior unsecured notes due 2020 | November | | $ | — |
| | $ | — |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | November | | — |
| | — |
| | 350 |
|
| Ameren Missouri: | | | | | | | |
| 3.65% Senior secured notes due 2045 | April | | — |
| | — |
| | 249 |
|
| 3.65% Senior secured notes due 2045 | June | | — |
| | 149 |
| | — |
|
| 2.95% Senior secured notes due 2027 | June | | 399 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | |
| 3.70% First mortgage bonds due 2047 | November | | 496 |
| | — |
| | — |
|
| 4.15% Senior secured notes due 2046 | December | | — |
| | 240 |
| | 248 |
|
| ATXI: | | | | | | | |
| 3.43% Senior notes due 2050 | June | | 150 |
| | — |
| | — |
|
| 3.43% Senior notes due 2050 | August | | 300 |
| | — |
| | — |
|
| Total long-term debt issuances | | | $ | 1,345 |
| | $ | 389 |
| | $ | 1,197 |
|
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | | | |
| Ameren Missouri: | | | | | | | |
| 5.40% Senior secured notes due 2016 | February | | — |
| | 260 |
| | — |
|
| 4.75% Senior secured notes due 2015 | April | | — |
| | — |
| | 114 |
|
| 6.40% Senior secured notes due 2017 | June | | 425 |
| | — |
| — | — |
|
| City of Bowling Green capital lease (Peno Creek CT) | December | | 6 |
| | 6 |
| | 6 |
|
| Ameren Illinois: | | | | | | | |
| 6.20% Senior secured notes due 2016 | June | | — |
| | 54 |
| | — |
|
| 6.25% Senior secured notes due 2016 | June | | — |
| | 75 |
| | — |
|
| 6.125% Senior secured notes due 2017 | November | | 250 |
| | — |
| | — |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 681 |
| | $ | 395 |
| | $ | 120 |
|
In June 2017, Ameren Missouri issued $400 million of 2.95% senior secured notes due June 2027, with interest payable semiannually For information on June 15 and December 15 of each year, beginning December 15, 2017. Ameren Missouricapital contributions received proceeds of $396 million, which were used, in conjunction with other available funds, to repay at maturity $425 million of Ameren Missouri’s 6.40% senior secured notes in June 2017.
In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes, due 2050, with interest payable semiannually on the last day of February and August of each year, beginning February 28, 2018, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes, which were used by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).
In November 2017, Ameren Illinois issued $500 million of 3.70% first mortgage bonds due December 2047, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2018. Ameren Illinois received proceeds of $492 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $250 million of its 6.125% senior secured notes that matured in November 2017.
In December 2017, Ameren, Ameren Missouri and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuancefrom Ameren (parent), see Note 13 – Related-party Transactions under Part II, Item 8 of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing and expires in December 2020.this report.
Ameren filed a Form S-3 registration statement with the SEC in May 2017, which expires in May 2020, 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.
|
| | | | | | | | | |
| | Month Issued, Redeemed, Repurchased, or Matured | | 2019 | | 2018 |
| Issuances of Long-term Debt | | | | | |
| Ameren: | | | | | |
| 2.50% Senior unsecured notes due 2024 | September | | $ | 450 |
| | $ | — |
|
| Ameren Missouri: | | | | | |
| 3.50% First mortgage bonds due 2029 | March | | 450 |
| | — |
|
| 3.25% First mortgage bonds due 2049 | October | | 328 |
| | — |
|
| 4.00% First mortgage bonds due 2048 | April | | — |
| | 423 |
|
| Ameren Illinois: | | | | | |
| 3.25% First mortgage bonds due 2050 | November | | 299 |
| | — |
|
| 3.80% First mortgage bonds due 2028 | May | | — |
| | 430 |
|
| 4.50% First mortgage bonds due 2049 | November | | — |
| | 499 |
|
| Total long-term debt issuances | | | $ | 1,527 |
| | $ | 1,352 |
|
| Issuances of Common Stock | | | | | |
| Ameren: | | | | | |
DRPlus and 401(k)(a)(b) | Various | | $ | 68 |
| | $ | 74 |
|
| Total common stock issuances | | | $ | 68 |
| | $ | 74 |
|
| Total Ameren long-term debt and common stock issuances | | | $ | 1,595 |
| | $ | 1,426 |
|
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | |
| Ameren Missouri: | | | | | |
| 6.70% Senior secured notes due 2019 | February | | $ | 329 |
| | $ | — |
|
| 5.10% Senior unsecured notes due 2019 | October | | 244 |
| | — |
|
| 5.45% First mortgage bonds due 2028 | October | | (c) |
| | |
| 6.00% Senior secured notes due 2018 | April | | — |
| | 179 |
|
| 5.10% Senior secured notes due 2018 | August | | — |
| | 199 |
|
| City of Bowling Green financing obligation (Peno Creek CT) | December | | 7 |
| | 6 |
|
| Ameren Illinois: | | | | | |
| 5.70% First mortgage bonds due 2024 | September | | (c) |
| | — |
|
| 5.90% First mortgage bonds due 2023 | October | | (c) |
| | — |
|
| 6.25% Senior secured notes due 2018 | April | | — |
| | 144 |
|
| 9.75% Senior secured notes due 2018 | November | | — |
| | 313 |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 580 |
| | $ | 841 |
|
| |
| (a) | Ameren issued a total of 0.9 million and 1.2 million shares of common stock under its DRPlus and 401(k) plan in 2019 and 2018, respectively. |
| |
| (b) | Excludes 0.8 million and 0.7 million shares of common stock valued at $54 million and $35 million issued for no cash consideration in connection with stock-based compensation in 2019 and 2018, respectively. |
| |
| (c) | Amount less than $1 million. |
The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. Any offer and sale will be made 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
At December 31, 2017,2019, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreement.
We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $431$472 million, or $1.778$1.9200 per share, in 2017, $4162019 and $451 million, or $1.715$1.8475 per share, in 2016, and $402 million, or $1.655 per share, in 2015.
2018. The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On February 9, 2018,14, 2020, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 45.7549.5 cents per share, payable on March 29, 2018,31, 2020, to shareholders of record on March 14, 2018.11, 2020.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances.
Ameren Illinois’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions with respect to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in itsthe capital structure at Ameren Illinois.
Ameren Missouri and Ameren Illinois, as well as certain other nonregistrant Ameren subsidiaries, are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and from retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on itstheir respective stock unless, among other things, itstheir respective earnings and earned surplus are sufficient to declare and pay a dividend after provision isprovisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.
At December 31, 2017,2019, the amount of restricted net assets of Ameren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $2.3$3.1 billion.
The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren Missouri and Ameren Illinoissubsidiaries to their parent, Ameren:
| | | | 2017 | | 2016 | | 2015 | 2019 | | 2018 |
| Ameren | $ | 431 |
| | $ | 416 |
| | $ | 402 |
| $ | 472 |
| | $ | 451 |
|
| Ameren Missouri | 362 |
| | 355 |
| | 575 |
| 430 |
| | 375 |
|
| Ameren Illinois | — |
| | 110 |
| | — |
| — |
| | — |
|
| ATXI | | 15 |
| | 75 |
|
Ameren Missouri and Ameren Illinois each have issued preferred stock, which provides for cumulative preferred stock dividends. Each company’s board of directors considers the declaration of the preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 20172019. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amountsplans, which are not included in the table below. In addition, routine short-term purchase order commitments are not included.
| | | | Less Than 1 Year | | 1 – 3 Years | | 3 – 5 Years | | After 5 Years | | Total | 2020 | | 2021 – 2022 | | 2023 – 2024 | | 2025 and Thereafter | | Total |
Ameren:(a) | | | | | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 841 |
| | $ | 1,023 |
| | $ | 514 |
| | $ | 5,617 |
| | $ | 7,995 |
| |
Interest payments(c) | 464 |
| | 855 |
| | 814 |
| | 5,018 |
| | 7,151 |
| |
Long-term debt and financing obligations(a) | | $ | 442 |
| | $ | 513 |
| | $ | 1,090 |
| | $ | 7,397 |
| | $ | 9,442 |
|
| Interest payments | | 378 |
| | 733 |
| | 674 |
| | 4,582 |
| | 6,367 |
|
| Operating leases | 10 |
| | 17 |
| | 12 |
| | 14 |
| | 53 |
| 8 |
| | 15 |
| | 11 |
| | 5 |
| | 39 |
|
Other obligations(d) | 981 |
| | 964 |
| | 206 |
| | 254 |
| | 2,405 |
| |
Other obligations(b) | | 763 |
| | 696 |
| | 260 |
| | 167 |
| | 1,886 |
|
| Total cash contractual obligations | $ | 2,296 |
| | $ | 2,859 |
| | $ | 1,546 |
| | $ | 10,903 |
| | $ | 17,604 |
| $ | 1,591 |
| | $ | 1,957 |
| | $ | 2,035 |
| | $ | 12,151 |
| | $ | 17,734 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 384 |
| | $ | 673 |
| | $ | 64 |
| | $ | 2,867 |
| | $ | 3,988 |
| |
Interest payments(c) | 331 |
| | 592 |
| | 575 |
| | 3,208 |
| | 4,706 |
| |
Long-term debt and financing obligations(a) | | $ | 92 |
| | $ | 63 |
| | $ | 590 |
| | $ | 3,484 |
| | $ | 4,229 |
|
| Interest payments | | 188 |
| | 373 |
| | 338 |
| | 2,140 |
| | 3,039 |
|
| Operating leases | 8 |
| | 15 |
| | 12 |
| | 14 |
| | 49 |
| 8 |
| | 13 |
| | 11 |
| | 5 |
| | 37 |
|
Other obligations(d) | 628 |
| | 654 |
| | 163 |
| | 194 |
| | 1,639 |
| |
Other obligations(b) | | 471 |
| | 501 |
| | 229 |
| | 109 |
| | 1,310 |
|
| Total cash contractual obligations | $ | 1,351 |
| | $ | 1,934 |
| | $ | 814 |
| | $ | 6,283 |
| | $ | 10,382 |
| $ | 759 |
| | $ | 950 |
| | $ | 1,168 |
| | $ | 5,738 |
| | $ | 8,615 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
Long-term debt(b)(a) | $ | 457 |
| | $ | — |
| | $ | 400 |
| | $ | 2,000 |
| | $ | 2,857 |
| $ | — |
| | $ | 400 |
| | $ | — |
| | $ | 3,213 |
| | $ | 3,613 |
|
Interest payments(c) | 106 |
| | 188 |
| | 185 |
| | 1,584 |
| | 2,063 |
| |
| Interest payments | | 143 |
| | 282 |
| | 264 |
| | 2,261 |
| | 2,950 |
|
| Operating leases | 1 |
| | — |
| | — |
| | 1 |
| | 2 |
| — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Other obligations(d) | 352 |
| | 310 |
| | 43 |
| | 40 |
| | 745 |
| |
Other obligations(b) | | 281 |
| | 190 |
| | 31 |
| | 24 |
| | 526 |
|
| Total cash contractual obligations | $ | 916 |
| | $ | 498 |
| | $ | 628 |
| | $ | 3,625 |
| | $ | 5,667 |
| $ | 424 |
| | $ | 874 |
| | $ | 295 |
| | $ | 5,498 |
| | $ | 7,091 |
|
| |
| (a) | Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations. |
| |
(b) | Excludes unamortized discount and premium and debt issuance costs of $60$85 million, $27$39 million,, and $27$38 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of this report, for discussion of items included herein. |
| |
(c) | The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2017.
|
| |
(d)(b) | See Other Obligations in Note 14 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein. |
As of December 31, 2017, Ameren, Ameren Missouri, and Ameren Illinois had no unrecognized tax benefits (detriments) for uncertain tax positions.
Off-Balance-SheetOff-balance-sheet Arrangements
At December 31, 2017,2019, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business,a forward sale agreement relating to common stock, variable interest entities, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for further detail concerning variable interest entities. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the forward sale agreement relating to common stock.
Credit Ratings
Our credit ratings affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.
The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:
|
| | |
| | Moody’s | S&P |
| Ameren: | | |
| Issuer/corporate credit rating | Baa1 | BBB+ |
| Senior unsecured debt | Baa1 | BBB |
| Commercial paper | P-2 | A-2 |
| Ameren Missouri: | | |
| Issuer/corporate credit rating | Baa1 | BBB+ |
| Secured debt | A2 | A |
| Senior unsecured debt | Baa1 | BBB+Not Rated |
| Commercial paper | P-2 | A-2 |
| Ameren Illinois: | | |
| Issuer/corporate credit rating | A3 | BBB+ |
| Secured debt | A1 | A |
| Senior unsecured debt | A3 | BBB+ |
| Commercial paper | P-2 | A-2 |
| ATXI: | | |
| Issuer credit rating | A2 | Not Rated |
| Senior unsecured debt | A2 | Not Rated |
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.
Collateral Postings
Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial at December 31, 2017.2019. A sub-investment-grade issuer or senior unsecured debt rating (whether(below “Baa3” from Moody’s or below “BBB-” from S&P or below “Baa3” from Moody’s)&P) at December 31, 2017,2019, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade obligations amounting to $82$143 million, $44$111 million, and $38$32 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2017,2019, if market prices were 15% higher or lower than December 31, 2017,2019 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade obligations.
OUTLOOK
We seek to earn competitive returns on investments in our businesses. We seek to improve our regulatory frameworks and cost recovery mechanisms and are simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity and allocating capital resources to business opportunities that we expect will offer the most attractive risk-adjusted return potential.
As part of Ameren’s strategic plan, we pursue projects to meet our customer energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories. Ameren also evaluates competitive electric transmission investment opportunities as they arise. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition to a more diverse energy generation portfolio.
Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 20182020 and beyond.
Operations
| |
| • | In 2018, Missouri Senate Bill 564 was enacted and Ameren Missouri elected the PISA in accordance with the provisions of the law. Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a return at the applicable WACC on investments in certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC, with all approved PISA deferrals added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense and a return at the applicable WACC for investments in renewable generation plant placed in service and not recovered under the PISA. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Ameren Missouri recognizes the cost of debt on PISA deferrals in revenue, instead of using the applicable WACC, with the difference recognized in revenues when recovery of such deferrals is reflected in customer rates. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. 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. |
| |
| • | In February 2020, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2020. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $7.6 billion over the five-year period from 2020 through 2024, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028. As a part of its Smart Energy Plan, Ameren Missouri expects to build solar generation facilities, including utility scale facilities and nonresidential customer site facilities. In September 2019, Ameren Missouri filed for certificates of convenience and necessity with the MoPSC to build three solar facilities in its service territory. Each 10-megawatt solar energy generation facility will connect to battery storage in order to improve system reliability. All three facilities are expected to be completed by 2022. Also in 2019, the MoPSC approved Ameren Missouri’s Charge Ahead program, which provides incentives for the development of over 1,000 electric vehicle charging stations along highways and at various locations in communities throughout Ameren Missouri’s service territory. The purpose of the program is to promote the development of electric vehicle charging infrastructure that will enable long-distance electric vehicle travel and encourage electrification of the transportation sector. |
In 2018, the MoPSC issued an order approving Ameren continuesMissouri’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 rate-adjustment mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65 million per year through 2021. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in FERC-regulatedactual MEEIA program costs and related lost electric transmission. ATXI has three MISO-approved multi-value projects, the Illinois Rivers, Spoon River, and Mark Twain projects. The Illinois Rivers project involves the construction of a transmission line from eastern
Missouri across Illinois to western Indiana. Construction activities for the Illinois Rivers project are continuing on schedule,margins and the last sectionamounts collected from customers. 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. If the target goals are achieved for 2019, 2020, and 2021, additional revenues of $7 million, $10 million, and $13 million would be recognized in late 2020, 2021, and 2022, respectively. Incremental additional revenues of $1 million, $3 million, and $3 million may be earned for 2019, 2020, and 2021, respectively, and would be recognized in the respective following year, if Ameren Missouri exceeds its targeted energy savings goals. Ameren Missouri recognized $28 million, $11 million, and $37 million in revenues related to MEEIA performance incentives in 2016, 2018, and 2019, respectively.
In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to elect to receive up to 100% of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election. Ameren Missouri is working to meet its customers’ top priorities for this project is expected to be completed by the end of 2019. The Spoon River project, located in northwest Illinois, was placed in service in February 2018. The Mark Twain project, located in northeast Missouri and connecting the Illinois Rivers project to Iowa, is expected to be completed by the end of 2019. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the Mark Twain project and its approval processprogram, including prices competitive with existing rates, long-term price predictability, and the Illinois Rivers project. Aspreference for renewable power generated in Missouri. Ameren Missouri has not yet developed a project that effectively meets the needs of December 31, 2017, ATXI’s expected remaining investmentthose customers who have expressed an interest in all three projects is approximately $300 million, with the total investmentprogram. Ameren Missouri will remain focused on finding solutions to be more than $1.6 billion. In addition, Ameren Illinois expects to invest $2.3 billion in electric transmission assets from 2018 through 2022 to replace aging infrastructurebest meet customer needs and improve reliability.expectations.
| |
| • | In July 2019, Ameren Missouri filed a request with the MoPSC seeking approval to decrease its annual revenues for electric service by $1 million. In February 2020, Ameren Missouri, the MoPSC staff, the MoOPC, and certain intervenors filed a nonunanimous stipulation and agreement with the MoPSC to decrease Ameren Missouri’s annual revenues for electric service by $32 million. The remaining intervenor did not object to the agreement. The stipulation and agreement, which is subject to MoPSC approval, specified an allowed ROE range of 9.4% to 9.8%, but did not specify the common equity percentage or rate base. The stipulation and agreement includes the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard compliance costs that the MoPSC previously authorized in earlier electric rate orders.Ameren Missouri cannot predict whether the MoPSC will approve the stipulation and agreement or, if approved, whether any application for rehearing or appeal will be filed, or the outcome if so filed. A decision by the MoPSC is expected by March 2020, with new rates effective as early as April 1, 2020.The percentage of net energy cost variances from the amount set in base rates allowed to be recovered or refunded under the FAC and costs from services provided by affiliates are still being challenged by the MoOPC, and are expected to be addressed in a proceeding that would begin in March 2020. A MoPSC decision would be expected in the proceeding by the end of May 2020. |
Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base growth and the currently allowed 10.82% return on common equity,10.38% ROE, the 2018 revenue requirements that will be included in 2020 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $270$311 million and $174$190 million, respectively. These revenue requirements represent an increase in Ameren Illinois'Illinois’ and ATXI'sATXI’s revenue requirements of $11$14 million and $4$13 million, respectively, primarily because offrom the rate base growth described above, partially offset by a decreaserevenue requirements reflected in 2019 rates, primarily due to the lower federal statutory corporate income taxexpected rate base growth. These rates enactedwill affect Ameren Illinois’ and ATXI’s cash receipts during 2020, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2020 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the TCJA.FERC formula ratemaking framework.
| |
| • | The ROE for MISO transmission owners, including Ameren Illinois and ATXI, is the subject of FERC complaint cases filed in November 2013 and February 2015 challenging the allowed base ROE. In November 2019, the FERC issued an order addressing the November 2013 complaint case, which set the allowed base ROE at 9.88% and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. The order also dismissed the February 2015 complaint case. As a result of this |
The return on common equity fororder, Ameren and Ameren Illinois expect to pay refunds of approximately $40 million and $23 million, respectively, in 2020. In December 2019, Ameren and the MISO transmission owners, including Ameren Illinois and ATXI, was the subject of a FERC complaint case filed in February 2015 which challenged the allowed base return on common equity.Missouri, Ameren Illinois, and ATXI, currently usefiled requests for rehearing with the FERC. Additionally, in December 2019, various parties filed requests for rehearing with the FERC, authorized totalchallenging the dismissal of the February 2015 complaint case.The FERC has not ruled on the merits of the rehearing requests and is under no deadline to do so.In March 2019, the FERC issued separate Notices of Inquiry regarding its allowed returnbase ROE policy and its transmission incentives policy. Initial comments were due by June 2019, and reply comments were due by late August 2019. The Notice of Inquiry addressing the FERC’s base ROE policy, among other things, broadened the ability to comment on common equitythe new methodology beyond electric utilities that are participants in the complaint cases. The transmission incentives Notice of 10.82% in customer rates. A final FERC order would establishInquiry was open for comment on the allowed return on common equity to be appliedFERC’s transmission incentive policy, including incentive adders to the 15-month period from February 2015base ROE. Ameren is unable to May 2016 and also establishpredict the return on common equity to be included in customer rates prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. The timing and amount of any adjustment to the total allowed return on common equity that may be ordered as a resultultimate impact of the complaint case is uncertain.Notices of Inquiry or the requests for rehearing at this time. A 50 basis point reduction in the FERC-allowed base return on common equityROE would reduce Ameren’s and Ameren Illinois’ annual earningsnet income by an estimated $8$10 million and $4$6 million, respectively, based on each company’s 20182020 projected rate base. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding FERC complaint cases.
| |
| • | Ameren Illinois’ electric distribution service performance-based formula ratemaking framework allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the year. Unless extended, the formula ratemaking framework expires at the end of 2022. If not extended, Ameren Illinois would then be required to establish future rates through a traditional regulatory rate review with the ICC. The decoupling provisions extend beyond the end of the formula ratemaking by law, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. |
In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared with the prior revenue requirement established in the MoPSC’s April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decreased by $54 million from the base level established in the MoPSC’s April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC’s April 2015 electric rate order.
In December 2017,2019, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $17 $7 million decrease in Ameren Illinois’ electric deliverydistribution service revenue requirementrates beginning in January 2018. However,2020. Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and investmenta return at the applicable WACC on year-end rate base in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois’ 20182020 electric distribution service revenues will be based on its 20182020 actual recoverable costs, 2020 year-end rate base, and return on common equityat the applicable WACC as calculated under the Illinois performance-based formula ratemaking framework. The 20182020 revenue requirement is expected to be comparable tohigher than the 20172019 revenue requirement because of an expected increase in recoverable costs and expected rate base growth of approximately 5%7%, andpartially offset by the impact of an expected increasedecrease in the annual average of the monthly average yieldyields of the 30-year United States Treasury bonds, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA.bonds. The 20182020 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2020.2022. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8$9 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 20182020 projected year-end rate base.
The FEJA allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. 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 monthly average yield 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.Pursuant to the FEJA, Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021 that will earn a return.Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments will be collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework. See Note 2 – Rate and
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| • | In February 2020, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $102 million, which included an estimated $46 million of annual revenues that would otherwise be recovered under the QIP and other riders. The request is based on a 10.5% allowed ROE, a capital structure composed of 54.1% common equity, and a rate base of $2.1 billion. |
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| • | Ameren Illinois earns a return at the applicable WACC on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the applicable WACC, with the ROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The allowed ROE 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. Pursuant to the FEJA, Ameren Illinois plans to invest up to approximately $100 million per year in electric energy-efficiency programs through 2024, and will earn a return on those investments.While the ICC has approved a plan consistent with this spending level through 2021, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs.The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not included in the electric distribution formula ratemaking framework. |
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| • | In February 2020, the MoPSC issued an order approving a stipulation and agreement allowing Ameren Missouri to defer and amortize maintenance expenses related to scheduled refueling and maintenance outages at its Callaway Energy Center.Beginning with the fall 2020 refueling and maintenance outage, Ameren Missouri will defer the maintenance expenses incurred related to a refueling and maintenance outage as a regulatory asset and amortize those expenses after completion of the outage. Maintenance expenses will be amortized over the period between refueling and maintenance outages, which is approximately 18 months. Ameren Missouri expects to incur approximately $40 million in maintenance expenses related to the fall 2020 outage. During a scheduled outage, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess |
Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ approved energy-efficiency program for 2018 through 2021.
In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49 million, which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider. The request was based on a 10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ Natural Gas Delivery Service Regulatory Rate Review.
Ameren Missouri’s next scheduled refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2019. During the 2017 refueling, Ameren Missouri incurred maintenance expenses of $35 million. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri may incur increased nonnuclear energy centerPrior to 2020, maintenance costs in non-outage years.
Amerenexpenses for refueling and Ameren Missouri expect an approximately $15 million decrease in annual interest chargesmaintenance outages were expensed as a result of the repayment of $425 million of Ameren Missouri’s 6.40% senior secured notes at maturity and issuance of $400 million 2.95% senior secured notes in 2017. In 2018, Ameren Missouri expects to refinance maturing long-term debt with lower-cost long-term debt, which would further reduce Ameren’s and Ameren Missouri’s annual interest charges.incurred.
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| • | As weAmeren Missouri and Ameren Illinois continue to make infrastructure investments and to experience cost increases, Ameren Missouri and Ameren Illinois expect to seek regularincreases to electric and natural gas rate increasesrates to recover the cost of investments and timely cost recovery and tracking mechanisms from their regulators.earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, legislative solutions as necessary, to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective technological advances, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy for efficiencies and as a means to address economywide CO2 emission concerns. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, result in rate base earningsand revenue growth but also higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property taxes, and higher state income taxes, among other costs.
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For additional information regarding recent rate orders, lawsuits, and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Liquidity and Capital Resources
In September 2017, Ameren Missouri filed its nonbinding 20-year integrated resource plan with the MoPSC. This plan includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability. The plan2017 IRP targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable sources by adding at least 700 megawatts of wind generation by the end of 2020 in Missouri and neighboring states, and adding 100 megawatts of solar generation overby 2027. These new renewable energy sources would support Ameren Missouri’s compliance with the next 10 years. The new wind generation facilities are expected to be located in Missouri and neighboring states. The source, location, and coststate of the new wind generation, among other items, remainMissouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to reaching agreements with developers.customer rate increase limitations. Based on current and projected market prices for energy and for wind and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost option for customers. The plan also provides for the expected implementation of continued customer energy-efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be affected by, among other factors: the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind and solar generation technologies, as well astechnologies; energy prices; Ameren Missouri’s ability to obtain timely interconnection agreements with the MISO or other RTOs including the cost of such interconnections;at an acceptable cost; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC, for projects located in Missouri, and any other required project approvals.
Ameren Missouri expects to file its next integrated resource plan in September 2020. Ameren Missouri will seek stakeholder feedback and assess different scenarios to meet future energy needs, which will be used to create an updated plan for its current generation portfolio and ongoing transition to cleaner sources of energy. | |
| • | In connection with the integrated resource plan2017 IRP filing, discussed above, Ameren Missouri established a goal of reducing CO2 emissions 80% by 2050 from a 2005 base level. To meet this goal, Ameren Missouri is also targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiringlevel. In order to meet these goals, among other things, Ameren Missouri expects to retire its coal-fired generation at the end of itseach energy center’s useful life. The Meramec, Sioux, Labadie, and Rush Island energy centers are expected to be retired in 2022, 2033, 2042, and 2045, respectively. |
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| • | Consistent with its 2017 IRP filing, in May 2019, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 300-megawatt wind generation facility.In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to400-megawatt wind generation facility. These two agreements are subject to customary contract terms and conditions. The two build-transfer acquisitions collectively represent $1.2 billion of capital expenditures, are expected to be completed by the end of 2020, and would support Ameren Missouri’s compliance with the Missouri renewable energy standard. Both acquisitions have received all regulatory approvals, and both projects have received all applicable zoning approvals, have entered into RTO interconnection agreements, and have begun construction activities. |
Through 2022,2024, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest up to $11.4$16.6 billion (Ameren Missouri – up to $4.5$8.4 billion; Ameren Illinois – up to $6.6$8.0 billion; ATXI – up to $0.3$0.2 billion) of capital expenditures during the period from 20182020 through 2022. These estimates do not reflect the potential additional investments identified in2024. Ameren’s and Ameren Missouri’s integrated resource planestimates exclude any capital expenditures related to pollution control equipment that may be required as a result of the NSR and Clean Air Act litigation discussed above, which could represent incremental investmentsin Note 14 – Commitments and Contingencies under Part II, Item 8, of approximately $1 billion through 2020 and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made.
this report. | |
| • | Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. Certain of these regulations are being challenged through litigation, or are being reviewed or recommended for repeal by the EPA, so theiror new replacement or alternative regulations are being contemplated, proposed, or adopted by the EPA and state regulators. The ultimate implementation of any of these regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates. |
expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.
The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1$2.3 billion of credit through December 2021,2024, subject to a 364-day repayment term in the case offor Ameren Missouri and Ameren Illinois.Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $2.7 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements.By the end of 2019, $951 million and $457 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
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| • | Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its plan to fund these cash flow requirements, Ameren is using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2024. Ameren expects these issuances to provide equity funding of about $100 million annually. Ameren also plans to issue incremental common equity to fund a portion of Ameren Missouri’s wind generation investments through the settlement of the forward sale agreement discussed below. Additionally, Ameren plans to issue incremental equity of about $150 million annually from 2021 to 2024.Ameren expects its equity to total capitalization to be about 45% through the period ending December 2024, with the long-term intent to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent). |
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| • | In August 2019, Ameren entered into a forward sale agreement with a counterparty relating to 7.5 million shares of common stock.The forward sale agreement can be settled at Ameren’s discretion on or prior to March 31, 2021. On a settlement date or dates, if Ameren elects to physically settle the forward sale agreement, Ameren will issue shares of common stock to the counterparty at the then-applicable forward sale price.The forward sale agreement will be physically settled unless Ameren elects to settle in cash or to net share settle. If physically settled, Ameren expects to receive between $540 million and $550 million upon settlement. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information. |
Federal income tax legislation enacted under the TCJA will continue to have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA, will benefit customers through lower rates for our services but is not expected to materially affect our earnings. However, our cash flows and rate base are expected to be materially affected inamong other things, reduced the near term. Our rate-regulated businesses recover income taxes in customer rates based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds from our customers for income taxes and when we pay such taxes. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expectedfrom 35% to be a decrease in operating cash flows. The decrease in operating cash flows results from21%, effective January 1, 2018. Customer rates were reduced customer rates, reflectingto reflect the lower income tax rate, decrease, without a corresponding reduction in income tax payments because of our use of net operating losses and tax credit carryforwards until about 2021. Additionally,2020. Customer rates were also reduced to reflect the return of excess deferred income taxes. The result of these customer rate reductions is a decrease in operating cash flows in the near term. Over time, the decrease in operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flowsoffset as a result of the TCJA is expected to be partially offset over timetemporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts once approved by our regulators. We expect rate base amounts to be higher as a result ofresulting from lower accumulated deferred income tax liabilities, due toliabilities.
The following table presents the eliminationnet regulatory liabilities/(assets) associated with excess deferred income taxes as of 50% accelerated tax depreciation, the reduced statutory income tax rate,December 31, 2019, and the return of excess deferred taxes to customers.Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion).related amortization periods:
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| Amortization Period | Ameren Missouri | | Ameren Illinois | | ATXI | | Total |
25 – 65 years | $ | 913 |
| | $ | 774 |
| | $ | 84 |
| | $ | 1,771 |
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6 – 10 years | 502 |
| | (3 | ) | | 1 |
| | 500 |
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| Total | $ | 1,415 |
| | $ | 771 |
| | $ | 85 |
| | $ | 2,271 |
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As of December 31, 2017,2019, Ameren had $235$98 million in tax benefits from federal and state net operating loss carryforwards and $120 million inrelated to federal and state income tax credit carryforwards. These carryforwards areAmeren has utilized all tax benefits from net operating loss carryforwards. Future expected to partially offset income tax obligations until 2021, at which time Ameren expects to begin making materialpayments and refunds are based on planned capital expenditures and any related income tax payments. Consistentcredits and, in the case of Ameren Missouri and Ameren Illinois, are consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries,subsidiaries. Ameren expects to make income tax payments between $5 million and $75 million in each year from 2020 to 2024, totaling $150 million to $200 million for the five-year period. Ameren Missouri and Ameren Illinois expectexpects to begin making materialmake income tax payments to Ameren (parent) beginningbetween $35 million and $45 million in 2018.
2020. Additionally, Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its plan to fund these cash requirements, beginning in the first quarter of 2018, Ameren will use newly issued shares, rather than market-purchased shares, to satisfy requirements under its DRPlus and employee benefit plans andMissouri expects to do so overreceive refunds from Ameren (parent) in each year from 2021 to 2024, totaling $60 million to $100 million for the next five years. Additionally,four-year period. Ameren may be requiredIllinois expects to issue incremental debt and/or equity, withmake income tax payments to Ameren (parent) between $20 million and $30 million in 2020 and between $50 million and $90 million in each year from 2021 to 2024, totaling $260 million to $310 million for the long-
five-year period.
term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. Ameren Missouri expects its 2020 wind generation acquisitions to generate federal production tax credits between $65 million and $70 million in each year from 2021 to 2030. Ameren Illinois expectexpects to fund cash flows needs through debt issuances, adjustmentsutilize approximately $140 million of dividendsthese federal production tax credits from 2021 to 2024. Delays in the timely completion of the wind generation facilities may affect the ability to realize some or all of the anticipated federal production tax credits. If these facilities are not completed in 2020, Ameren (parent), and/Missouri will need to satisfy additional IRS requirements in order to qualify for some or capital contributions from Ameren (parent), withall of the intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.anticipated federal production tax credits.
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| • | In 2018, legislation modifying Missouri tax law was enacted to decrease the state’s corporate income tax rate from 6.25% to 4%, effective January 1, 2020.Ameren Missouri anticipates that the effect of this tax decrease will be reflected in customer rates upon completion of its current electric service regulatory rate review. Ameren (parent) and nonregistrant subsidiaries do not expect this income tax decrease to have a material impact on net income. |
The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and 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 under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are the most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
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| Accounting Estimate | | Uncertainties Affecting Application |
Regulatory Mechanisms and Cost Recovery
We defer costs and recognize revenues that we intend to collect in future rates.
Regulatory environment and external regulatory decisions and requirements
Anticipated future regulatory decisions and our assessment of their impact
The impact of prudence reviews, complaint cases, limitations on electric rate increases in Missouri, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments
Ameren Illinois’ assessment of and ability to estimate the current year’s electric deliverydistribution service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking framework
Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks
Ameren Missouri’s estimate of revenue recovery under the MEEIA plans
Any adjustments related to the TCJA
Basis for Judgment
The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, legislation, or historical experience, as well as discussions with legal counsel. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers. We also recognize revenues for alternative revenue programs authorized by our regulators that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months following the end of the annual period in which they are recognized. Under performance-based formula ratemaking, which expires at the end of 2022 unless extended, Ameren Illinois estimates its annual electric distribution revenue requirement pursuant to the IEIMA for interim periods by using internal forecasted rate base and published forecasted data regarding that year’sthe annual average of the monthly average yields of the 30-year United States Treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31 of each year using that year’s actual operating results and assesses the probability of recovery from or refund to customers that the ICC will order at the end of the following year. Variations in investments made or orders by the ICC or courts can result in a subsequent change in Ameren Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates lost revenueselectric margins resulting from its MEEIA customer energy-efficiency programs. Ameren Missouri uses aprograms, which are subsequently recovered through the MEEIA rider to collect from or refund to customers any annual difference in the actual amounts incurred and the amounts collected from customers. The Ameren Companies made provisional estimates to deferred tax balances as a result of the TCJA. The revaluation of certain deferred taxes was deferred as a regulatory asset or liability on the balance sheet and will be collected from or refunded to customers as determined by our regulators. These estimates are subject to change, as discussed in the Accounting for Income Taxes section below.rider. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a description of our regulatory mechanisms and quantification of these assets or liabilities
for each of the Ameren Companies. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for a listing of regulatory mechanisms used by Ameren Missouri and Ameren Illinois.
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of providing future employee benefits for the benefit plans we offer our employees. See Note 10 – Retirement Benefits under Part II, Item 8, of this report.
Future rate of return on pension and other plan assets
Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable
Discount rate
Future compensation increase assumption
Health care cost trend rates
Timing of employee retirements and mortality assumptions
Ability to recover certain benefit plan costs from our customers
Changing market conditions that may affect investment and interest rate environments
Basis for Judgment
Ameren has defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren has defined benefit pension plans covering substantially all of its non-union employees and postretirement benefit plans covering non-union employees hired before October 2015. Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable. We also make mortality assumptions to estimate our pension and other postretirement benefit obligations. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for these assumptions and the sensitivity of Ameren’s benefit plans to potential changes in these assumptions.
Accounting for Contingencies
We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and that the amount of the loss can be reasonably estimated.
Estimating financial impact of events
Estimating likelihood of various potential outcomes
Regulatory and political environments and requirements
Outcome of legal proceedings, settlements, or other factors
Changes in regulation, expected scope of work, technology, or timing of environmental remediation
Basis for Judgment
The determination of a loss contingency requires significant judgment as to the expected outcome of the contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider the nature of the litigation, the claim or assessment, opinions or views of legal counsel, and the expected outcome of potential litigation, among other things. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. The amount recorded for any contingency may differ from actual costs incurred when the contingency is resolved. Contingencies are normally resolved over long periods of time. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. 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 for information on the Ameren Companies’ contingencies.
Accounting for Income Taxes
We record a provision for income taxes, deferred tax assets and liabilities, and a valuation allowance against net deferred tax assets, if any. See Note 12 – Income Taxes under Part II, Item 8, of this report.
Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations
Estimates of the amount and character of future taxable income and forecasted use of our tax credit carryforwards
Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled
Effectiveness of implementing tax planning strategies
Changes in income tax laws, including amounts subject to income tax, and the regulatory treatment of any tax reform changes
Results of audits and examinations by taxing authorities
Basis for Judgment
The reporting of tax-related assets and liabilities requires the use of estimates and significant management judgment. Deferred tax assets and liabilities are recorded to represent future effects on income taxes for temporary differences between the basis of assets for financial reporting and tax purposes. Although management believes that current estimates for deferred tax assets and liabilities are reasonable, actual results could differ from these estimates for a variety of reasons, includingincluding: a change in forecasted financial condition and/or results of operations, changeoperations; changes in income tax laws, enacted tax rates or amounts subject to income tax,tax; the form, structure, and timing of asset or stock sales or dispositions, changedispositions; changes in the regulatory treatment of any tax reform benefits,benefits; and results ofchanges resulting from audits and examinations by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At each period end, and as new developments occur, management reevaluates its tax positions. Additional interpretations, regulations, amendments, or technical corrections related to the federal income tax code as a result of the TCJA, as well as the associated treatment by our regulators, may impact the estimates for income taxes discussed above. See Note 12 – Income Taxes under Part II, Item 8, of this report for the amount of deferred income taxes recorded at December 31, 20172019.
Unbilled RevenueAccounting for Asset Retirement Obligations
AtWe record the endestimated fair value of eachlegal obligations associated with the retirement of tangible long-lived assets. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
Discount rates
Cost escalation rates
Changes in regulation, expected scope of work, technology, or timing of environmental remediation
Estimates as to the probability, timing, or amount of cash expenditures associated with AROs
Basis for Judgment
We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred or when sufficient information becomes available to determine fair value and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs based on changes in the estimated fair values of the obligations with a corresponding increase or decrease in the asset book value. We estimate the fair value of our AROs using present value techniques, in which we make various assumptions about discount rates and cost escalation rates. In addition, these estimates include assumptions of the probability, timing, and amount of cash expenditures to settle the ARO, and are based on currently available technology. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with Ameren Missouri’s Callaway Energy Center decommissioning, CCR facilities, and river structures. Also, Ameren, Ameren Missouri, and Ameren Illinois estimatehave recorded AROs for retirement costs associated with asbestos removal and the usage that has been provided to customers but not yet billed. This usage amount, along with a per unit price, is used to estimate an unbilled balance. For its electric distribution business, Ameren Illinois then considers and reflectsdisposal of certain transformers. An increase of 0.25% in the effect of the decoupling provisions of the FEJA.
Estimating customer energy usage
Estimating impacts of weather and other usage-affecting factors for the unbilled period
Estimating loss of energy during transmission and delivery
Basis for Judgment
We base our estimate of unbilled revenue each period on the volume of energy delivered, as valuedassumed escalation rates would increase Ameren’s AROs at December 31, 2019 by a model of billing cycles and historical usage rates and by growth or contraction by customer class for our service area. This figure is then adjusted for the modeled impact of seasonal and weather variations based on historical results. As a result of its regulatory framework, Ameren Illinois adjusts unbilled electric distribution revenues to reflect the decoupling provisions of the FEJA, with an offset to a regulatory asset or liability.$35 million. See the balance sheet for each of the Ameren CompaniesNote 15 – Supplemental Information under Part II, Item 8, of this report for unbilled revenue amounts.the amount of AROs recorded at December 31, 2019.
Impact of New Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
EFFECTS OF INFLATION AND CHANGING PRICES
Ameren’s rates for retail electric and natural gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by the FERC. Rate regulation is generally based on the recovery of historical or projected costs. As a result, revenue increases could lag behind changing prices. Ameren Illinois’ and ATXI’s electric transmissionThe current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, customer rates are determined pursuantdesigned to formula ratemaking. Additionally, provide recovery of historical costs through depreciation might not be adequate to replace plant in future years.
Ameren Illinois participates in performance-based formula ratemaking frameworks established pursuant to the IEIMA and the FEJA for its electric distribution business and its electric energy-efficiency investments. Within Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Within the IEIMA and the FEJAIllinois’ formula ratemaking frameworks, the annual average of the monthly average yields of the 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity.allowed ROE. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the annual return on equityallowed ROE applicable to Ameren Illinois’ electric distribution business and electric energy-efficiency investments. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates in a subsequent year.
The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, customer rates designed to provide recovery of historical costs through depreciation might not be adequate to replace plant in future years.
Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. The March 2017 MoPSC electric rate order approved Ameren Missouri’s request for continued use ofHowever, the FAC; however, the FAC
excludes substantially all transmission revenues and charges. Ameren Missouri is therefore exposed to transmission charges to the extent that they exceed transmission revenues. Ameren Illinois is required to purchase all of its expected power supply through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.
In our Missouri and Illinois retail natural gas utility jurisdictions, changes in natural gas costs are generally reflected in billings to natural gas customers through PGA clauses.
See Part I, Item 1, and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on our cost recovery mechanisms.
| |
| ITEM 7A. | 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 or index. 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 objectives are to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
long-term and short-term variable-rate debt;
fixed-rate debt;
United States Treasury bonds; and
the discount rate applicable to asset retirement obligations, goodwill, and defined pension and postretirement benefit plans, asset retirement obligations, and goodwill.plans.
We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio and by monitoring the effects of market changes on interest rates. For defined pension and postretirement benefit plans, we control the duration and the portfolio mix of our plan assets. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information related to asset retirement obligations, goodwill, and the defined pension and postretirement benefit plans.
The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 100 basis points on variable-rate debt outstanding at December 31, 2017:2019 is immaterial.
|
| | | | | | |
| | | Interest Expense | | Net Income(a) |
| Ameren | $ | 7 |
| $ | (5 | ) |
| Ameren Missouri | | 2 |
| | (2 | ) |
| Ameren Illinois | | 1 |
| | (1 | ) |
| |
(a) | Calculations are based on the 2018 statutory tax rates of 27%, 25%, and 28% for Ameren, Ameren Missouri, and Ameren Illinois, respectively. |
The returnallowed ROE under Ameren Illinois’ electric distribution service and its electric energy-efficiency investments formula ratemaking recovery mechanisms is based on equity component under the IEIMA and the FEJA is equal to the calendar yearannual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworksROE for both its electric distribution service and its electric energy-efficiency investmentsbusiness is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8$9 million change in Ameren’s and Ameren Illinois’ annual net income, based on its 20182020 projected rate base. Interest rate levels also influence the ROE allowed by our regulators in our other ratemaking jurisdictions as well as the carrying costs associated with certain regulatory assets and liabilities.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and carry only a nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See
Note 7 – Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2017.2019.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables 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 December 31, 2017,2019, no nonaffiliated customer represented more than 10% of our accounts receivable. Additionally, Ameren Illinois faces risks associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois may be required to purchase the supplier’s receivables relating to Ameren Illinois’ distribution customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers to reflect charges for electric distribution and purchased receivables. As of December 31, 2017,2019, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $31$32 million. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rate adjustmentrate-adjustment mechanism that allows Ameren Illinois to recover the difference between its actual net bad debt write-offs under GAAP and the amount of net bad debt write-offs included in its base rates. Ameren Missouri and Ameren Illinois continue to monitor the impact of increasing rates on customer collections.collections, as applicable. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.
Investment Price Risk
Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and company-owned life insurance contracts include equity and debt securities. The equity securities are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates.
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide benefits at the time they are payable, while also maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class are estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjust the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns, and for the effect of expenses paid from plan assets. Contributions to the plans and future costs could increase materially if we do not achieve pension and postretirement asset portfolio investment returns equal to or in excess of our 20182020 assumed return on plan assets of 7.00%.
Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2017,2019, this fund was invested in domestic equity securities (66%(67%) and debt securities (33%(32%). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the trust assets to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Additionally, Ameren and Ameren Illinois have company-owned life insurance contracts with net asset values of $136$150 million and $9 million, respectively, as of December 31, 2017.2019. Changes in the market values of these contracts are reflected in earnings.
Commodity Price Risk
Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businessesbusinesses’ exposure to changing market prices for commodities is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and natural gas supply.
Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their customers. The effects of price volatility cannot be eliminated. However, procurement and sales strategies involve risk management techniques and instruments, as well as the management of physical assets.
Ameren Missouri has a FAC that allows it 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 regulatory rate proceeding,review, subject to MoPSC prudence reviews. Ameren Missouri remains exposed to the remaining 5% of such changes.
Ameren Illinois has a cost recovery mechanismmechanisms for power purchased, on behalfcapacity, zero emission credit, and renewable energy credit costs and expects full recovery of its customers.such costs. Ameren Illinois is required to serve as the provider of last resort for electric customers in its service territory who have not chosen an alternative retail electric supplier. In 2019, Ameren Illinois does not generate earnings basedprocured power on the resalebehalf of power but rather on the deliveryits customers for 22% of energy.its total kilowatthour sales. Ameren Illinois purchases power primarilyenergy and capacity through the MISO with additionaland through bilateral contracts resulting from IPA procurement events administered by the IPA.events. The IPA has proposed and the ICC has approved multiple procurement events covering portions of years through 2020. In 2017, acting in its role as the provider of last resort,2022 for capacity and energy. Ameren Illinois supplied powerhas also entered into ICC-approved contracts for 23%zero emission credits through 2026 and for renewable energy credits with 15-year terms commencing on the date of its kilowatthour sales to its electric customers.first renewable energy credit delivery. Ameren Illinois expects full recoverydoes not generate earnings based on the resale of its purchased power costs.or purchase of zero emission credits or renewable energy credits but rather on the delivery of the energy.
Ameren Missouri and Ameren Illinois have PGA clauses that permit costs incurred for natural gas to be recovered directly from utility customers without a traditional regulatory rate proceeding,review, subject to prudence review.reviews.
The following table presents, as of December 31, 2019, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri’s coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway Energy Center, natural gas for Ameren Missouri’s retail distribution, and purchased power for Ameren Illinois that are price-hedged over the period 2020 through 2024. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
|
| | | | | | | | |
| | 2020 | | 2021 | | 2022 - 2024 |
| Ameren: | | | | | |
| Coal | 100 | % | | 94 | % | | 36 | % |
| Coal transportation | 100 |
| | 100 |
| | 98 |
|
| Nuclear fuel | 90 |
| | (a) |
| | 72(a) |
|
Natural gas for distribution(b) | 77 |
| | 34 |
| | 10 |
|
Purchased power for Ameren Illinois(c) | 69 |
| | 35 |
| | 11 |
|
| Ameren Missouri: | | | | | |
| Coal | 100 | % | | 94 | % | | 36 | % |
| Coal transportation | 100 |
| | 100 |
| | 97 |
|
| Nuclear fuel | 90 |
| | (a) |
| | 72(a) |
|
Natural gas for distribution(b) | 65 |
| | 34 |
| | 9 |
|
| Ameren Illinois: | | | | | |
Natural gas for distribution(b) | 79 | % | | 34 | % | | 10 | % |
Purchased power(c) | 69 |
| | 35 |
| | 11 |
|
| |
| (a) | The Callaway Energy Center requires refueling at 18-month intervals. The next refueling is scheduled for the fall of 2020. As there are no refuelings scheduled to occur during 2021 or 2024, there are also no nuclear fuel deliveries anticipated to occur in these years. |
| |
| (b) | Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2020 represents January 2020 through March 2020. The year 2021 represents November 2020 through March 2021. This continues each successive year through March 2024. |
| |
| (c) | Represents the percentage of purchased power price-hedged for fixed-price residential and nonresidential customers with less than 150 kilowatts of demand. |
Our exposure to commodity price risk for construction and maintenance activities is related to changes in market prices for metal commodities and to labor availability.
See Transmission and Supply of Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear, natural gas, oil, and renewables. Also see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.
Commodity Supplier Risk
The use of ultra-low-sulfurlow-sulfur coal is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has agreements with multiple suppliers to purchase ultra-low-sulfurlow-sulfur coal through 20212025 to comply with environmental regulations. Disruptions to the deliveries of ultra-low-sulfurlow-sulfur coal from a supplier could compromise Ameren Missouri’s ability to operate in compliance with emission standards. The suppliers of ultra-low-sulfurlow-sulfur coal are limited, and the construction of pollution control equipment requires significant lead time. If Ameren Missouri were to experience a temporary disruption of ultra-low-sulfurlow-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of ultra-low-sulfurlow-sulfur coal were not available, Ameren Missouri would have to use its existing emission allowances, purchase emission allowances to achieve compliance with environmental regulations, or purchase power necessary to meet demand.
The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse, which is the only NRC-licensed
During 2019, one of Ameren Missouri’s low-sulfur coal suppliers and a partial owner of another supplier authorized to provide fuel assemblies to the Callaway energy center. During the first quarter of 2017, Westinghouse filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believereplaced any resulting volume shortfall through its other coal supply contracts and through the restructuring proceeding will not affect Westinghouse’s performance under the termsuse of its existing contracts withinventory. As such, Ameren Missouri and therefore dodid not expectexperience any material impact to Ameren Missouri’s operations. However, Ameren and Ameren Missouri could incur material unexpected costsits operations as a result of these restructuring proceedings. As of December 31, 2019, both entities have emerged from bankruptcy proceedings and shipments of low-sulfur coal have resumed in accordance with Ameren Missouri’s supply contracts in place with the Westinghouseaffected suppliers prior to the bankruptcy such asproceedings.
Currently, the loss of fuel inventory that is stored at Westinghouse’s facility and the cost of replacement power ifCallaway Energy Center uses nuclear fuel assemblies were not available forof a future scheduled refueling and maintenance outage. A change of fuel suppliers ordesign fabricated by only a change in the type of fuel assembly design thatsingle supplier. That supplier is currently licensed for use atthe only NRC-licensed supplier able to provide fuel assemblies to the Callaway energy center could takeEnergy Center. Ameren Missouri is pursuing a program to qualify an estimated three years of analysisalternate NRC-licensed supplier, and expects to obtain NRC licensing efforts to implement. See Note 9 – Callaway Energy Center under Part II, Item 8, of this report for additional information.approval in 2023.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2017. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 8 – Fair Value Measurements under Part II, Item 8, of this report for additional information regarding the methods used to determine the fair value of these contracts.
|
| | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fair value of contracts at beginning of year, net | $ | (4 | ) | | $ | (180 | ) | | $ | (184 | ) |
| Contracts realized or otherwise settled during the period | (3 | ) | | 4 |
| | 1 |
|
| Fair value of new contracts entered into during the period | 11 |
| | (7 | ) | | 4 |
|
| Other changes in fair value | 4 |
| | (34 | ) | | (30 | ) |
| Fair value of contracts outstanding at end of year, net | $ | 8 |
| | $ | (217 | ) | | $ | (209 | ) |
The following table presents maturities of derivative contracts as of December 31, 2017, based on the hierarchy levels used to determine the fair value of the contracts:
|
| | | | | | | | | | | | | | | | | | | |
| Sources of Fair Value | Maturity Less Than 1 Year | | Maturity 1 – 3 Years | | Maturity
3 – 5 Years | | Maturity in Excess of 5 Years | | Total Fair Value |
| Ameren Missouri: |
| |
| |
| |
| |
|
| Level 1 | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Level 2(a) | (3 | ) | | (3 | ) | | — |
| | — |
| | (6 | ) |
Level 3(b) | 8 |
| | 2 |
| | — |
| | — |
| | 10 |
|
| Total | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Ameren Illinois: |
|
| |
|
| |
|
| |
|
| |
|
|
| Level 1 | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) |
Level 2(a) | (10 | ) | | (7 | ) | | (1 | ) | | — |
| | (18 | ) |
Level 3(b) | (14 | ) | | (30 | ) | | (29 | ) | | (125 | ) | | (198 | ) |
| Total | $ | (25 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (217 | ) |
| Ameren: | | | | | | | | | |
| Level 1 | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
Level 2(a) | (13 | ) | | (10 | ) | | (1 | ) | | — |
| | (24 | ) |
Level 3(b) | (6 | ) | | (28 | ) | | (29 | ) | | (125 | ) | | (188 | ) |
| Total | $ | (17 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (209 | ) |
| |
(a)
| Principally fixed-price vs. floating OTC power swaps, power forwards, and fixed-price vs. floating OTC natural gas swaps. |
| |
(b) | Principally power forward contract values based on information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on an option valuation model. |
| |
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 20172019 and 2016,2018, and the related consolidated statements of income and comprehensive income, changes inof shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2017,2019, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016,2018, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2017,2019, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation
As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. The Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from, or returned to, customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2019, the Company’s consolidated balance sheet reflected $1.1 billion of regulatory assets and $5.1 billion of regulatory liabilities. As disclosed by management, in some cases, management must apply judgment related to the probability of recovery if regulatory balances are recorded before approval has been received from the regulator or probability of refund of amounts collected in rates that may be returned to customers. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are there was significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator and (iii) regulatory assets meeting the alternative revenue program criteria. This resulted in significant auditor judgment and effort when performing audit procedures and evaluating audit evidence relating to management’s application of regulatory accounting, assessment of probability of recovery, and expected timing of collection within 24 months of the end of the annual period in which they are recognized.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders, legislation, or external legal counsel correspondence, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and testing the expected timing of collection within 24 months of the end of the annual period in which they are recognized.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 20182020
We have served as the Company’s auditor since at least 1932. We have not determinedbeen able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric Company:Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Union Electric Company (the “Company”) as of December 31, 20172019 and 2016,2018, and the related statements of income, and comprehensive income, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2017,2019, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’sfinancial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 20182020
We have served as the Company’s auditor since at least 1932. We have not determinedbeen able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois Company:Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ameren Illinois Company (the “Company”) as of December 31, 20172019 and 2016,2018, and the related statements of income, and comprehensive income, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2017,2019, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’sfinancial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 20182020
We have served as the Company’s auditor since 1998.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (In millions, except per share amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
|
| Natural gas | 867 |
| | 880 |
| | 918 |
|
| Total operating revenues | 6,177 |
| | 6,076 |
| | 6,098 |
|
| Operating Expenses: |
| |
| | |
| Fuel | 737 |
| | 745 |
| | 878 |
|
| Purchased power | 638 |
| | 621 |
| | 514 |
|
| Natural gas purchased for resale | 311 |
| | 341 |
| | 415 |
|
| Other operations and maintenance | 1,660 |
| | 1,676 |
| | 1,694 |
|
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 896 |
| | 845 |
| | 796 |
|
| Taxes other than income taxes | 477 |
| | 467 |
| | 473 |
|
| Total operating expenses | 4,719 |
| | 4,695 |
| | 4,839 |
|
| Operating Income | 1,458 |
| | 1,381 |
| | 1,259 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 59 |
| | 74 |
| | 74 |
|
| Miscellaneous expense | 21 |
| | 32 |
| | 30 |
|
| Total other income | 38 |
| | 42 |
| | 44 |
|
| Interest Charges | 391 |
| | 382 |
| | 355 |
|
| Income Before Income Taxes | 1,105 |
| | 1,041 |
| | 948 |
|
| Income Taxes | 576 |
| | 382 |
| | 363 |
|
| Income from Continuing Operations | 529 |
| | 659 |
| | 585 |
|
| Income from Discontinued Operations, Net of Taxes | — |
| | — |
| | 51 |
|
| Net Income | 529 |
| | 659 |
| | 636 |
|
Less: Net Income from Continuing Operations Attributable to
Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Net Income Attributable to Ameren Common Shareholders: | | | | | |
| Continuing Operations | 523 |
| | 653 |
| | 579 |
|
| Discontinued Operations | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | |
| Earnings per Common Share – Basic: | | | | | |
| Continuing Operations | $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.39 |
|
| Discontinued Operations | — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Basic | $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.60 |
|
| | | | | | |
| Earnings per Common Share – Diluted: | | | | | |
| Continuing Operations | $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.38 |
|
| Discontinued Operations | — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Diluted | $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.59 |
|
| | | | | | |
| Dividends per Common Share | $ | 1.778 |
| | $ | 1.715 |
| | $ | 1.655 |
|
| Average Common Shares Outstanding – Basic | 242.6 |
| | 242.6 |
| | 242.6 |
|
| Average Common Shares Outstanding – Diluted | 244.2 |
| | 243.4 |
| | 243.6 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions, except per share amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 4,981 |
| | $ | 5,339 |
| | $ | 5,307 |
|
| Natural gas | 929 |
| | 952 |
| | 867 |
|
| Total operating revenues | 5,910 |
| | 6,291 |
| | 6,174 |
|
| Operating Expenses: |
| |
| | |
| Fuel | 535 |
| | 769 |
| | 737 |
|
| Purchased power | 556 |
| | 581 |
| | 638 |
|
| Natural gas purchased for resale | 331 |
| | 374 |
| | 311 |
|
| Other operations and maintenance | 1,745 |
| | 1,772 |
| | 1,705 |
|
| Depreciation and amortization | 995 |
| | 955 |
| | 896 |
|
| Taxes other than income taxes | 481 |
| | 483 |
| | 477 |
|
| Total operating expenses | 4,643 |
| | 4,934 |
| | 4,764 |
|
| Operating Income | 1,267 |
| | 1,357 |
| | 1,410 |
|
| Other Income, Net | 130 |
| | 102 |
| | 86 |
|
| Interest Charges | 381 |
| | 401 |
| | 391 |
|
| Income Before Income Taxes | 1,016 |
| | 1,058 |
| | 1,105 |
|
| Income Taxes | 182 |
| | 237 |
| | 576 |
|
| Net Income | 834 |
| | 821 |
| | 529 |
|
| Less: Net Income Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 828 |
| | $ | 815 |
| | $ | 523 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 834 |
| | $ | 821 |
| | $ | 529 |
|
| Other Comprehensive Income (Loss), Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $1, $(1), and $3, respectively | 5 |
| | (4 | ) | | 5 |
|
| Comprehensive Income | 839 |
| | 817 |
| | 534 |
|
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 833 |
| | $ | 811 |
| | $ | 528 |
|
| | | | | | |
| | | | | | |
| Earnings per Common Share – Basic | $ | 3.37 |
| | $ | 3.34 |
| | $ | 2.16 |
|
| | | | | | |
| Earnings per Common Share – Diluted | $ | 3.35 |
| | $ | 3.32 |
| | $ | 2.14 |
|
| | | | | | |
| Weighted-average Common Shares Outstanding – Basic | 245.6 |
| | 243.8 |
| | 242.6 |
|
| Weighted-average Common Shares Outstanding – Diluted | 247.1 |
| | 245.8 |
| | 244.2 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Income from Continuing Operations | $ | 529 |
| | $ | 659 |
| | $ | 585 |
|
| Other Comprehensive Income (Loss) from Continuing Operations, Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $3, respectively | 5 |
| | (20 | ) | | 6 |
|
| Comprehensive Income from Continuing Operations | 534 |
| | 639 |
| | 591 |
|
| Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 528 |
| | 633 |
| | 585 |
|
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) |
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 16 |
| | $ | 16 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $17 and $18, respectively) | 393 |
| | 463 |
|
| Unbilled revenue | 278 |
| | 295 |
|
| Miscellaneous accounts receivable | 63 |
| | 79 |
|
| Inventories | 494 |
| | 483 |
|
| Current regulatory assets | 69 |
| | 134 |
|
| Other current assets | 118 |
| | 63 |
|
| Total current assets | 1,431 |
| | 1,533 |
|
| Property, Plant, and Equipment, Net | 24,376 |
| | 22,810 |
|
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 847 |
| | 684 |
|
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 992 |
| | 1,127 |
|
| Other assets | 876 |
| | 650 |
|
| Total investments and other assets | 3,126 |
| | 2,872 |
|
| TOTAL ASSETS | $ | 28,933 |
| | $ | 27,215 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 442 |
| | $ | 580 |
|
| Short-term debt | 440 |
| | 597 |
|
| Accounts and wages payable | 874 |
| | 817 |
|
| Current regulatory liabilities | 164 |
| | 149 |
|
| Other current liabilities | 585 |
| | 544 |
|
| Total current liabilities | 2,505 |
| | 2,687 |
|
| Long-term Debt, Net | 8,915 |
| | 7,859 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 2,919 |
| | 2,666 |
|
| Regulatory liabilities | 4,887 |
| | 4,637 |
|
| Asset retirement obligations | 638 |
| | 627 |
|
| Pension and other postretirement benefits | 401 |
| | 558 |
|
| Other deferred credits and liabilities | 467 |
| | 408 |
|
| Total deferred credits and other liabilities | 9,312 |
| | 8,896 |
|
| Commitments and Contingencies (Notes 2, 9, and 14) |
|
| |
|
|
| Ameren Corporation Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 246.2 and 244.5, respectively | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,694 |
| | 5,627 |
|
| Retained earnings | 2,380 |
| | 2,024 |
|
| Accumulated other comprehensive loss | (17 | ) | | (22 | ) |
| Total Ameren Corporation shareholders’ equity | 8,059 |
| | 7,631 |
|
| Noncontrolling Interests | 142 |
| | 142 |
|
| Total equity | 8,201 |
| | 7,773 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 28,933 |
| | $ | 27,215 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) |
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 10 |
| | $ | 9 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively) | 445 |
| | 437 |
|
| Unbilled revenue | 323 |
| | 295 |
|
| Miscellaneous accounts and notes receivable | 70 |
| | 63 |
|
| Inventories | 522 |
| | 527 |
|
| Current regulatory assets | 144 |
| | 149 |
|
| Other current assets | 98 |
| | 113 |
|
| Total current assets | 1,612 |
| | 1,593 |
|
| Property, Plant, and Equipment, Net | 21,466 |
| | 20,113 |
|
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 704 |
| | 607 |
|
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 1,230 |
| | 1,437 |
|
| Other assets | 522 |
| | 538 |
|
| Total investments and other assets | 2,867 |
| | 2,993 |
|
| TOTAL ASSETS | $ | 25,945 |
| | $ | 24,699 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 841 |
| | $ | 681 |
|
| Short-term debt | 484 |
| | 558 |
|
| Accounts and wages payable | 902 |
| | 805 |
|
| Taxes accrued | 52 |
| | 46 |
|
| Interest accrued | 99 |
| | 93 |
|
| Customer deposits | 108 |
| | 107 |
|
| Current regulatory liabilities | 128 |
| | 110 |
|
| Other current liabilities | 326 |
| | 274 |
|
| Total current liabilities | 2,940 |
| | 2,674 |
|
| Long-term Debt, Net | 7,094 |
| | 6,595 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 2,506 |
| | 4,264 |
|
| Accumulated deferred investment tax credits | 49 |
| | 55 |
|
| Regulatory liabilities | 4,387 |
| | 1,985 |
|
| Asset retirement obligations | 638 |
| | 635 |
|
| Pension and other postretirement benefits | 545 |
| | 769 |
|
| Other deferred credits and liabilities | 460 |
| | 477 |
|
| Total deferred credits and other liabilities | 8,585 |
| | 8,185 |
|
| Commitments and Contingencies (Notes 2, 9, and 14) |
|
| |
|
|
| Ameren Corporation Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,540 |
| | 5,556 |
|
| Retained earnings | 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (18 | ) | | (23 | ) |
| Total Ameren Corporation shareholders’ equity | 7,184 |
| | 7,103 |
|
| Noncontrolling Interests | 142 |
| | 142 |
|
| Total equity | 7,326 |
| | 7,245 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 25,945 |
| | $ | 24,699 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 834 |
| | $ | 821 |
| | $ | 529 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 1,002 |
| | 938 |
| | 876 |
|
| Amortization of nuclear fuel | 79 |
| | 95 |
| | 76 |
|
| Amortization of debt issuance costs and premium/discounts | 19 |
| | 20 |
| | 22 |
|
| Deferred income taxes and investment tax credits, net | 167 |
| | 224 |
| | 539 |
|
| Allowance for equity funds used during construction | (28 | ) | | (36 | ) | | (24 | ) |
| Stock-based compensation costs | 20 |
| | 20 |
| | 17 |
|
| Other | (14 | ) | | 44 |
| | (10 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | 79 |
| | (24 | ) | | (53 | ) |
| Inventories | (10 | ) | | 39 |
| | 17 |
|
| Accounts and wages payable | (3 | ) | | (22 | ) | | 32 |
|
| Taxes accrued | (8 | ) | | (10 | ) | | 55 |
|
| Regulatory assets and liabilities | 164 |
| | 201 |
| | 36 |
|
| Assets, other | (59 | ) | | 2 |
| | 34 |
|
| Liabilities, other | (33 | ) | | (117 | ) | | (7 | ) |
| Pension and other postretirement benefits | (39 | ) | | (25 | ) | | (21 | ) |
| Net cash provided by operating activities | 2,170 |
| | 2,170 |
| | 2,118 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (2,411 | ) | | (2,286 | ) | | (2,132 | ) |
| Nuclear fuel expenditures | (31 | ) | | (52 | ) | | (63 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (256 | ) | | (315 | ) | | (321 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 260 |
| | 299 |
| | 305 |
|
| Purchase of bonds | (207 | ) | | — |
| | — |
|
| Proceeds from sale of remarketed bonds | 207 |
| | — |
| | — |
|
| Other | 3 |
| | 18 |
| | 7 |
|
| Net cash used in investing activities | (2,435 | ) | | (2,336 | ) | | (2,204 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (472 | ) | | (451 | ) | | (431 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt, net | (157 | ) | | 112 |
| | (74 | ) |
| Maturities of long-term debt | (580 | ) | | (841 | ) | | (681 | ) |
| Issuances of long-term debt | 1,527 |
| | 1,352 |
| | 1,345 |
|
| Issuances of common stock | 68 |
| | 74 |
| | — |
|
| Repurchases of common stock for stock-based compensation | — |
| | — |
| | (24 | ) |
| Employee payroll taxes related to stock-based compensation | (29 | ) | | (19 | ) | | (15 | ) |
| Debt issuance costs | (17 | ) | | (14 | ) | | (11 | ) |
| Other | — |
| | (2 | ) | | (1 | ) |
| Net cash provided by financing activities | 334 |
| | 205 |
| | 102 |
|
| Net change in cash, cash equivalents, and restricted cash | 69 |
| | 39 |
| | 16 |
|
| Cash, cash equivalents, and restricted cash at beginning of year | 107 |
| | 68 |
| | 52 |
|
| Cash, cash equivalents, and restricted cash at end of year | $ | 176 |
| | $ | 107 |
| | $ | 68 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $20, $21, and $14 capitalized, respectively) | $ | 367 |
| | $ | 387 |
| | $ | 370 |
|
| Income taxes, net | 13 |
| | 21 |
| | (19 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 529 |
| | $ | 659 |
| | $ | 636 |
|
| Income from discontinued operations, net of tax | — |
| | — |
| | (51 | ) |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 876 |
| | 835 |
| | 777 |
|
| Amortization of nuclear fuel | 76 |
| | 88 |
| | 97 |
|
| Amortization of debt issuance costs and premium/discounts | 22 |
| | 22 |
| | 22 |
|
| Deferred income taxes and investment tax credits, net | 539 |
| | 386 |
| | 369 |
|
| Allowance for equity funds used during construction | (24 | ) | | (27 | ) | | (30 | ) |
| Share-based compensation costs | 17 |
| | 17 |
| | 24 |
|
| Other | (10 | ) | | 4 |
| | (10 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | (53 | ) | | (71 | ) | | 83 |
|
| Inventories | 17 |
| | 11 |
| | (14 | ) |
| Accounts and wages payable | 32 |
| | 19 |
| | (2 | ) |
| Taxes accrued | 55 |
| | 13 |
| | (22 | ) |
| Regulatory assets and liabilities | 36 |
| | 215 |
| | 94 |
|
| Assets, other | 20 |
| | (22 | ) | | 46 |
|
| Liabilities, other | (7 | ) | | (9 | ) | | (44 | ) |
| Pension and other postretirement benefits | (21 | ) | | (16 | ) | | (9 | ) |
| Net cash provided by operating activities – continuing operations | 2,104 |
| | 2,124 |
| | 2,035 |
|
| Net cash used in operating activities – discontinued operations | — |
| | (1 | ) | | (4 | ) |
| Net cash provided by operating activities | 2,104 |
| | 2,123 |
| | 2,031 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (2,132 | ) | | (2,076 | ) | | (1,917 | ) |
| Nuclear fuel expenditures | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 396 |
| | 377 |
| | 349 |
|
| Other | 7 |
| | 5 |
| | 32 |
|
| Net cash used in investing activities – continuing operations | (2,205 | ) | | (2,141 | ) | | (1,951 | ) |
| Net cash used in investing activities – discontinued operations | — |
| | — |
| | (25 | ) |
| Net cash used in investing activities | (2,205 | ) | | (2,141 | ) | | (1,976 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (431 | ) | | (416 | ) | | (402 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt, net | (74 | ) | | 257 |
| | (413 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (681 | ) | | (395 | ) | | (120 | ) |
| Issuances of long-term debt | 1,345 |
| | 389 |
| | 1,197 |
|
| Debt issuance costs | (11 | ) | | (9 | ) | | (12 | ) |
| Share-based payments | (39 | ) | | (83 | ) | | (12 | ) |
| Other | (1 | ) | | (2 | ) | | — |
|
| Net cash provided by (used in) financing activities – continuing operations | 102 |
| | (265 | ) | | 232 |
|
| Net change in cash and cash equivalents | 1 |
| | (283 | ) | | 287 |
|
| Cash and cash equivalents at beginning of year | 9 |
| | 292 |
| | 5 |
|
| Cash and cash equivalents at end of year | $ | 10 |
| | $ | 9 |
| | $ | 292 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $14, $15, and $17 capitalized, respectively) | $ | 370 |
| | $ | 358 |
| | $ | 335 |
|
| Income taxes, net | (19 | ) | | (12 | ) | | (15 | ) |
AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2017 |
| Common Stock | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 5,627 |
| | 5,540 |
| | 5,556 |
|
| Shares issued under the DRPlus and 401(k) plan | 68 |
| | 74 |
| | — |
|
| Stock-based compensation activity | (1 | ) | | 13 |
| | (16 | ) |
| Other paid-in capital, end of year | 5,694 |
| | 5,627 |
| | 5,540 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 2,024 |
| | 1,660 |
| | 1,568 |
|
| Net income attributable to Ameren common shareholders | 828 |
| | 815 |
| | 523 |
|
| Dividends | (472 | ) | | (451 | ) | | (431 | ) |
| Retained earnings, end of year | 2,380 |
| | 2,024 |
| | 1,660 |
|
| | | | | | |
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| Deferred retirement benefit costs, beginning of year | (22 | ) | | (18 | ) | | (23 | ) |
| Change in deferred retirement benefit costs | 5 |
| | (4 | ) | | 5 |
|
| Deferred retirement benefit costs, end of year | (17 | ) | | (22 | ) | | (18 | ) |
| Total accumulated other comprehensive loss, end of year | (17 | ) | | (22 | ) | | (18 | ) |
| Total Ameren Corporation Shareholders’ Equity | $ | 8,059 |
| | $ | 7,631 |
| | $ | 7,184 |
|
| | | | | | |
| Noncontrolling Interests: | | | | | |
| Beginning of year | 142 |
| | 142 |
| | 142 |
|
| Net income attributable to noncontrolling interest holders | 6 |
| | 6 |
| | 6 |
|
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Noncontrolling interests, end of year | 142 |
| | 142 |
| | 142 |
|
| Total Equity | $ | 8,201 |
| | $ | 7,773 |
| | $ | 7,326 |
|
| | | | | | |
| | | | | | |
| Common stock shares outstanding at beginning of year | 244.5 |
| | 242.6 |
| | 242.6 |
|
| Shares issued under the DRPlus and 401(k) plan | 0.9 |
| | 1.2 |
| | — |
|
| Shares issued for stock-based compensation | 0.8 |
| | 0.7 |
| | — |
|
| Common stock shares outstanding at end of year | 246.2 |
| | 244.5 |
| | 242.6 |
|
| | | | | | |
| Dividends per common share | $ | 1.9200 |
| | $ | 1.8475 |
| | $ | 1.7775 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Common Stock | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 5,556 |
| | 5,616 |
| | 5,617 |
|
| Share-based compensation activity | (16 | ) | | (60 | ) | | (1 | ) |
| Other paid-in capital, end of year | 5,540 |
| | 5,556 |
| | 5,616 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 1,568 |
| | 1,331 |
| | 1,103 |
|
| Net income attributable to Ameren common shareholders | 523 |
| | 653 |
| | 630 |
|
| Dividends | (431 | ) | | (416 | ) | | (402 | ) |
| Retained earnings, end of year | 1,660 |
| | 1,568 |
| | 1,331 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| Deferred retirement benefit costs, beginning of year | (23 | ) | | (3 | ) | | (9 | ) |
| Change in deferred retirement benefit costs | 5 |
| | (20 | ) | | 6 |
|
| Deferred retirement benefit costs, end of year | (18 | ) | | (23 | ) | | (3 | ) |
| Total accumulated other comprehensive loss, end of year | (18 | ) | | (23 | ) | | (3 | ) |
| Total Ameren Corporation Shareholders’ Equity | $ | 7,184 |
| | $ | 7,103 |
| | $ | 6,946 |
|
| | | | | | |
| Noncontrolling Interests: | | | | | |
| Beginning of year | 142 |
| | 142 |
| | 142 |
|
| Net income attributable to noncontrolling interest holders | 6 |
| | 6 |
| | 6 |
|
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Noncontrolling interests, end of year | 142 |
| | 142 |
| | 142 |
|
| Total Equity | $ | 7,326 |
| | $ | 7,245 |
| | $ | 7,088 |
|
| | | | | | |
| Common stock shares at end of year | 242.6 |
| | 242.6 |
| | 242.6 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 |
| 2018 | | 2017 |
| Operating Revenues: |
|
|
| | |
| Electric | $ | 3,109 |
|
| $ | 3,451 |
| | $ | 3,411 |
|
| Natural gas | 134 |
|
| 138 |
| | 126 |
|
| Total operating revenues | 3,243 |
|
| 3,589 |
| | 3,537 |
|
| Operating Expenses: |
|
|
| | |
| Fuel | 535 |
|
| 769 |
| | 737 |
|
| Purchased power | 193 |
|
| 164 |
| | 245 |
|
| Natural gas purchased for resale | 53 |
| | 56 |
| | 47 |
|
| Other operations and maintenance | 960 |
| | 972 |
| | 925 |
|
| Depreciation and amortization | 556 |
| | 550 |
| | 533 |
|
| Taxes other than income taxes | 329 |
| | 329 |
| | 328 |
|
| Total operating expenses | 2,626 |
| | 2,840 |
| | 2,815 |
|
| Operating Income | 617 |
| | 749 |
| | 722 |
|
| Other Income, Net | 58 |
| | 56 |
| | 65 |
|
| Interest Charges | 178 |
| | 200 |
| | 207 |
|
| Income Before Income Taxes | 497 |
| | 605 |
| | 580 |
|
| Income Taxes | 68 |
| | 124 |
| | 254 |
|
| Net Income | $ | 429 |
| | $ | 481 |
| | $ | 326 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 426 |
| | $ | 478 |
| | $ | 323 |
|
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 |
| 2016 | | 2015 |
| Operating Revenues: |
|
|
| | |
| Electric | $ | 3,413 |
|
| $ | 3,394 |
| | $ | 3,470 |
|
| Natural gas | 126 |
|
| 128 |
| | 137 |
|
| Other | — |
|
| 1 |
| | 2 |
|
| Total operating revenues | 3,539 |
|
| 3,523 |
| | 3,609 |
|
| Operating Expenses: |
|
|
| | |
| Fuel | 737 |
|
| 745 |
| | 878 |
|
| Purchased power | 245 |
|
| 252 |
| | 111 |
|
| Natural gas purchased for resale | 47 |
| | 49 |
| | 57 |
|
| Other operations and maintenance | 902 |
| | 893 |
| | 925 |
|
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 533 |
| | 514 |
| | 492 |
|
| Taxes other than income taxes | 328 |
| | 325 |
| | 335 |
|
| Total operating expenses | 2,792 |
| | 2,778 |
| | 2,867 |
|
| Operating Income | 747 |
| | 745 |
| | 742 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 48 |
| | 52 |
| | 52 |
|
| Miscellaneous expense | 8 |
| | 10 |
| | 11 |
|
| Total other income | 40 |
| | 42 |
| | 41 |
|
| Interest Charges | 207 |
| | 211 |
| | 219 |
|
| Income Before Income Taxes | 580 |
| | 576 |
| | 564 |
|
| Income Taxes | 254 |
| | 216 |
| | 209 |
|
| Net Income | 326 |
| | 360 |
| | 355 |
|
| Other Comprehensive Income | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 323 |
| | $ | 357 |
| | $ | 352 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) |
| | | December 31, | December 31, |
| | 2017 | | 2016 | 2019 | | 2018 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| $ | 9 |
| | $ | — |
|
| Advances to money pool | — |
| | 161 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively) | 200 |
| | 187 |
| 164 |
| | 223 |
|
| Accounts receivable – affiliates | 11 |
| | 12 |
| 30 |
| | 14 |
|
| Unbilled revenue | 165 |
| | 154 |
| 139 |
| | 155 |
|
| Miscellaneous accounts and notes receivable | 35 |
| | 14 |
| |
| Miscellaneous accounts receivable | | 33 |
| | 42 |
|
| Inventories | 388 |
| | 392 |
| 373 |
| | 358 |
|
| Current regulatory assets | 56 |
| | 35 |
| |
| Other current assets | 50 |
| | 49 |
| 66 |
| | 40 |
|
| Total current assets | 905 |
| | 1,004 |
| 814 |
| | 832 |
|
| Property, Plant, and Equipment, Net | 11,751 |
| | 11,478 |
| 12,635 |
| | 12,103 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 704 |
| | 607 |
| 847 |
| | 684 |
|
| Regulatory assets | 395 |
| | 619 |
| 285 |
| | 366 |
|
| Other assets | 288 |
| | 327 |
| 356 |
| | 306 |
|
| Total investments and other assets | 1,387 |
| | 1,553 |
| 1,488 |
| | 1,356 |
|
| TOTAL ASSETS | $ | 14,043 |
| | $ | 14,035 |
| $ | 14,937 |
| | $ | 14,291 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 384 |
| | $ | 431 |
| $ | 92 |
| | $ | 580 |
|
| Short-term debt | 39 |
| | — |
| 234 |
| | 55 |
|
| Accounts and wages payable | 475 |
| | 444 |
| 465 |
| | 428 |
|
| Accounts payable – affiliates | 60 |
| | 68 |
| 52 |
| | 69 |
|
| Taxes accrued | 30 |
| | 30 |
| |
| Interest accrued | 54 |
| | 54 |
| |
| Current regulatory liabilities | 19 |
| | 12 |
| 62 |
| | 68 |
|
| Other current liabilities | 103 |
| | 123 |
| 221 |
| | 202 |
|
| Total current liabilities | 1,164 |
| | 1,162 |
| 1,126 |
| | 1,402 |
|
| Long-term Debt, Net | 3,577 |
| | 3,563 |
| 4,098 |
| | 3,418 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 1,650 |
| | 3,013 |
| |
| Accumulated deferred investment tax credits | 48 |
| | 53 |
| |
| Accumulated deferred income taxes and investment tax credits, net | | 1,612 |
| | 1,576 |
|
| Regulatory liabilities | 2,664 |
| | 1,215 |
| 2,937 |
| | 2,799 |
|
| Asset retirement obligations | 634 |
| | 629 |
| 634 |
| | 623 |
|
| Pension and other postretirement benefits | 213 |
| | 291 |
| 141 |
| | 228 |
|
| Other deferred credits and liabilities | 12 |
| | 19 |
| 40 |
| | 16 |
|
| Total deferred credits and other liabilities | 5,221 |
| | 5,220 |
| 5,364 |
| | 5,242 |
|
| Commitments and Contingencies (Notes 2, 9, 13, and 14) |
| |
|
| |
|
| Shareholders’ Equity: | | | | | | |
| Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 |
| | 511 |
| 511 |
| | 511 |
|
| Other paid-in capital, principally premium on common stock | 1,858 |
| | 1,828 |
| 2,027 |
| | 1,903 |
|
| Preferred stock | 80 |
| | 80 |
| 80 |
| | 80 |
|
| Retained earnings | 1,632 |
| | 1,671 |
| 1,731 |
| | 1,735 |
|
| Total shareholders’ equity | 4,081 |
| | 4,090 |
| 4,349 |
| | 4,229 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 14,043 |
| | $ | 14,035 |
| $ | 14,937 |
| | $ | 14,291 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF CASH FLOWS (In millions) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF CASH FLOWS (In millions) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF CASH FLOWS (In millions) |
| | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 326 |
| | $ | 360 |
| | $ | 355 |
| $ | 429 |
| | $ | 481 |
| | $ | 326 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
| |
| Depreciation and amortization | 514 |
| | 506 |
| | 476 |
| 564 |
| | 533 |
| | 514 |
|
| Amortization of nuclear fuel | 76 |
| | 88 |
| | 97 |
| 79 |
| | 95 |
| | 76 |
|
| Amortization of debt issuance costs and premium/discounts | 6 |
| | 6 |
| | 6 |
| 5 |
| | 6 |
| | 6 |
|
| Deferred income taxes and investment tax credits, net | 82 |
| | 179 |
| | 82 |
| (19 | ) | | (9 | ) | | 82 |
|
| Allowance for equity funds used during construction | (21 | ) | | (23 | ) | | (22 | ) | (19 | ) | | (27 | ) | | (21 | ) |
| Other | 4 |
| | 5 |
| | 2 |
| 13 |
| | 17 |
| | 4 |
|
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | (46 | ) | | 5 |
| | 72 |
| 75 |
| | (32 | ) | | (46 | ) |
| Inventories | 18 |
| | (4 | ) | | (39 | ) | (13 | ) | | 30 |
| | 18 |
|
| Accounts and wages payable | 27 |
| | (18 | ) | | 3 |
| 16 |
| | (21 | ) | | 27 |
|
| Taxes accrued | (1 | ) | | 11 |
| | 1 |
| (15 | ) | | (1 | ) | | (1 | ) |
| Regulatory assets and liabilities | 26 |
| | 84 |
| | 117 |
| 17 |
| | 201 |
| | 26 |
|
| Assets, other | 30 |
| | (25 | ) | | 26 |
| (28 | ) | | 2 |
| | 31 |
|
| Liabilities, other | (23 | ) | | (1 | ) | | 4 |
| (32 | ) | | (13 | ) | | (23 | ) |
| Pension and other postretirement benefits | (2 | ) | | (4 | ) | | (2 | ) | (5 | ) | | (2 | ) | | (2 | ) |
| Net cash provided by operating activities | 1,016 |
| | 1,169 |
| | 1,247 |
| 1,067 |
| | 1,260 |
| | 1,017 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (773 | ) | | (738 | ) | | (622 | ) | (1,076 | ) | | (914 | ) | | (773 | ) |
| Nuclear fuel expenditures | (63 | ) | | (55 | ) | | (52 | ) | (31 | ) | | (52 | ) | | (63 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (413 | ) | | (392 | ) | | (363 | ) | (256 | ) | | (315 | ) | | (321 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 396 |
| | 377 |
| | 349 |
| 260 |
| | 299 |
| | 305 |
|
| Purchase of bonds | | (207 | ) | | — |
| | — |
|
| Proceeds from sale of remarketed bonds | | 207 |
| | — |
| | — |
|
| Money pool advances, net | 161 |
| | (125 | ) | | (36 | ) | — |
| | — |
| | 161 |
|
| Other | 7 |
| | (1 | ) | | — |
| 8 |
| | 6 |
| | 7 |
|
| Net cash used in investing activities | (685 | ) | | (934 | ) | | (724 | ) | (1,095 | ) | | (976 | ) | | (684 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Dividends on common stock | (362 | ) | | (355 | ) | | (575 | ) | (430 | ) | | (375 | ) | | (362 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 39 |
| | — |
| | (97 | ) | 179 |
| | 16 |
| | 39 |
|
| Redemptions, repurchases, and maturities of long-term debt | (431 | ) | | (266 | ) | | (120 | ) | |
| Maturities of long-term debt | | (580 | ) | | (384 | ) | | (431 | ) |
| Issuances of long-term debt | 399 |
| | 149 |
| | 249 |
| 778 |
| | 423 |
| | 399 |
|
| Capital issuance costs | (3 | ) | | (3 | ) | | (3 | ) | |
| Debt issuance costs | | (9 | ) | | (5 | ) | | (3 | ) |
| Capital contribution from parent | 30 |
| | 44 |
| | 224 |
| 124 |
| | 45 |
| | 30 |
|
| Net cash used in financing activities | (331 | ) | | (434 | ) | | (325 | ) | |
| Net change in cash and cash equivalents | — |
| | (199 | ) | | 198 |
| |
| Cash and cash equivalents at beginning of year | — |
| | 199 |
| | 1 |
| |
| Cash and cash equivalents at end of year | $ | — |
| | $ | — |
| | $ | 199 |
| |
| | | | | | | |
Noncash financing activity – capital contribution from parent | $ | — |
| | $ | — |
| | $ | 38 |
| |
| Net cash provided by (used in) financing activities | | 59 |
| | (283 | ) | | (331 | ) |
| Net change in cash, cash equivalents, and restricted cash | | 31 |
| | 1 |
| | 2 |
|
| Cash, cash equivalents, and restricted cash at beginning of year | | 8 |
| | 7 |
| | 5 |
|
| Cash, cash equivalents, and restricted cash at end of year | | $ | 39 |
| | $ | 8 |
| | $ | 7 |
|
| | | | | | | | | | | |
| Cash Paid During the Year: | | | | | | | | | | |
| Interest (net of $10, $12, and $12 capitalized, respectively) | $ | 202 |
| | $ | 209 |
| | $ | 212 |
| |
| Interest (net of $12, $14, and $10 capitalized, respectively) | | $ | 190 |
| | $ | 196 |
| | $ | 202 |
|
| Income taxes, net | 178 |
| | 27 |
| | 72 |
| 101 |
| | 128 |
| | 178 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | December 31, | December 31, |
| | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
| $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| | | | | | | | | | | |
| Other Paid-in Capital: | | | | | | | | | | |
| Beginning of year | 1,828 |
| | 1,822 |
| | 1,569 |
| 1,903 |
| | 1,858 |
| | 1,828 |
|
| Capital contribution from parent | 30 |
| | 6 |
| | 253 |
| 124 |
| | 45 |
| | 30 |
|
| Other paid-in capital, end of year | 1,858 |
| | 1,828 |
| | 1,822 |
| 2,027 |
| | 1,903 |
| | 1,858 |
|
| | | | | | | | | | | |
| Preferred Stock | 80 |
| | 80 |
| | 80 |
| 80 |
| | 80 |
| | 80 |
|
| | | | | | | | | | | |
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 1,671 |
| | 1,669 |
| | 1,892 |
| 1,735 |
| | 1,632 |
| | 1,671 |
|
| Net income | 326 |
| | 360 |
| | 355 |
| 429 |
| | 481 |
| | 326 |
|
| Common stock dividends | (362 | ) | | (355 | ) | | (575 | ) | (430 | ) | | (375 | ) | | (362 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,632 |
| | 1,671 |
| | 1,669 |
| 1,731 |
| | 1,735 |
| | 1,632 |
|
| | | | | | | | | | | |
| Total Shareholders’ Equity | $ | 4,081 |
| | $ | 4,090 |
| | $ | 4,082 |
| $ | 4,349 |
| | $ | 4,229 |
| | $ | 4,081 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Operating Revenues: | | | | | |
| Electric | $ | 1,730 |
| | $ | 1,761 |
| | $ | 1,784 |
|
| Natural gas | 797 |
| | 815 |
| | 743 |
|
| Total operating revenues | 2,527 |
| | 2,576 |
| | 2,527 |
|
| Operating Expenses: | | | | | |
| Purchased power | 368 |
| | 429 |
| | 417 |
|
| Natural gas purchased for resale | 278 |
| | 318 |
| | 264 |
|
| Other operations and maintenance | 782 |
| | 799 |
| | 799 |
|
| Depreciation and amortization | 406 |
| | 374 |
| | 341 |
|
| Taxes other than income taxes | 143 |
| | 144 |
| | 137 |
|
| Total operating expenses | 1,977 |
| | 2,064 |
| | 1,958 |
|
| Operating Income | 550 |
| | 512 |
| | 569 |
|
| Other Income, Net | 53 |
| | 42 |
| | 12 |
|
| Interest Charges | 147 |
| | 149 |
| | 144 |
|
| Income Before Income Taxes | 456 |
| | 405 |
| | 437 |
|
| Income Taxes | 110 |
| | 98 |
| | 166 |
|
| Net Income | $ | 346 |
| | $ | 307 |
| | $ | 271 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 343 |
| | $ | 304 |
| | $ | 268 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Operating Revenues: | | | | | |
| Electric | $ | 1,784 |
| | $ | 1,736 |
| | $ | 1,683 |
|
| Natural gas | 743 |
| | 754 |
| | 783 |
|
| Other | 1 |
| | — |
| | — |
|
| Total operating revenues | 2,528 |
| | 2,490 |
| | 2,466 |
|
| Operating Expenses: | | | | | |
| Purchased power | 417 |
| | 399 |
| | 420 |
|
| Natural gas purchased for resale | 264 |
| | 292 |
| | 358 |
|
| Other operations and maintenance | 789 |
| | 804 |
| | 797 |
|
| Depreciation and amortization | 341 |
| | 319 |
| | 295 |
|
| Taxes other than income taxes | 137 |
| | 132 |
| | 130 |
|
| Total operating expenses | 1,948 |
| | 1,946 |
| | 2,000 |
|
| Operating Income | 580 |
| | 544 |
| | 466 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 11 |
| | 21 |
| | 21 |
|
| Miscellaneous expense | 10 |
| | 12 |
| | 12 |
|
| Total other income | 1 |
| | 9 |
| | 9 |
|
| Interest Charges | 144 |
| | 140 |
| | 131 |
|
| Income Before Income Taxes | 437 |
| | 413 |
| | 344 |
|
| Income Taxes | 166 |
| | 158 |
| | 127 |
|
| Net Income | 271 |
| | 255 |
| | 217 |
|
| Other Comprehensive Loss, Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $-, $(1), and $(2), respectively | — |
| | (5 | ) | | (3 | ) |
| Comprehensive Income | $ | 271 |
| | $ | 250 |
| | $ | 214 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 268 |
| | $ | 252 |
| | $ | 214 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) BALANCE SHEET (In millions) | AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) BALANCE SHEET (In millions) | AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) BALANCE SHEET (In millions) |
| | | December 31, | December 31, |
| | 2017 | | 2016 | 2019 | | 2018 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively) | 234 |
| | 242 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $10 and $11, respectively) | | 215 |
| | 224 |
|
| Accounts receivable – affiliates | 9 |
| | 10 |
| 28 |
| | 21 |
|
| Unbilled revenue | 158 |
| | 141 |
| 139 |
| | 140 |
|
| Miscellaneous accounts receivable | 35 |
| | 22 |
| 25 |
| | 40 |
|
| Inventories | 134 |
| | 135 |
| 121 |
| | 125 |
|
| Current regulatory assets | 87 |
| | 108 |
| 57 |
| | 110 |
|
| Other current assets | 15 |
| | 25 |
| 29 |
| | 16 |
|
| Total current assets | 672 |
| | 683 |
| 614 |
| | 676 |
|
| Property, Plant, and Equipment, Net | 8,293 |
| | 7,469 |
| 10,083 |
| | 9,198 |
|
| Investments and Other Assets: | | | |
| |
|
| Goodwill | 411 |
| | 411 |
| 411 |
| | 411 |
|
| Regulatory assets | 822 |
| | 816 |
| 694 |
| | 759 |
|
| Other assets | 147 |
| | 95 |
| 383 |
| | 275 |
|
| Total investments and other assets | 1,380 |
| | 1,322 |
| 1,488 |
| | 1,445 |
|
| TOTAL ASSETS | $ | 10,345 |
| | $ | 9,474 |
| $ | 12,185 |
| | $ | 11,319 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 457 |
| | $ | 250 |
| |
| Short-term debt | 62 |
| | 51 |
| $ | 53 |
| | $ | 72 |
|
| Accounts and wages payable | 337 |
| | 264 |
| 299 |
| | 302 |
|
| Accounts payable – affiliates | 70 |
| | 63 |
| 82 |
| | 58 |
|
| Taxes accrued | 19 |
| | 16 |
| |
| Interest accrued | 33 |
| | 33 |
| |
| Customer deposits | 69 |
| | 69 |
| 77 |
| | 76 |
|
| Current environmental remediation | 42 |
| | 38 |
| 42 |
| | 42 |
|
| Current regulatory liabilities | 92 |
| | 78 |
| 84 |
| | 62 |
|
| Other current liabilities | 177 |
| | 109 |
| 207 |
| | 184 |
|
| Total current liabilities | 1,358 |
| | 971 |
| 844 |
| | 796 |
|
| Long-term Debt, Net | 2,373 |
| | 2,338 |
| 3,575 |
| | 3,296 |
|
| Deferred Credits and Other Liabilities: | | | |
| |
|
| Accumulated deferred income taxes, net | 1,021 |
| | 1,631 |
| |
| Accumulated deferred investment tax credits | 1 |
| | 2 |
| |
| Accumulated deferred income taxes and investment tax credits, net | | 1,224 |
| | 1,119 |
|
| Regulatory liabilities | 1,629 |
| | 768 |
| 1,849 |
| | 1,741 |
|
| Pension and other postretirement benefits | 285 |
| | 346 |
| 214 |
| | 280 |
|
| Environmental remediation | 134 |
| | 162 |
| 87 |
| | 109 |
|
| Other deferred credits and liabilities | 234 |
| | 222 |
| 260 |
| | 204 |
|
| Total deferred credits and other liabilities | 3,304 |
| | 3,131 |
| 3,634 |
| | 3,453 |
|
| Commitments and Contingencies (Notes 2, 13, and 14) |
|
| |
|
|
|
| |
|
|
| Shareholders’ Equity: | | | |
| |
|
| Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | — |
| | — |
| — |
| | — |
|
| Other paid-in capital | 2,013 |
| | 2,005 |
| 2,188 |
| | 2,173 |
|
| Preferred stock | 62 |
| | 62 |
| 62 |
| | 62 |
|
| Retained earnings | 1,235 |
| | 967 |
| 1,882 |
| | 1,539 |
|
| Total shareholders’ equity | 3,310 |
| | 3,034 |
| 4,132 |
| | 3,774 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 10,345 |
| | $ | 9,474 |
| $ | 12,185 |
| | $ | 11,319 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 346 |
| | $ | 307 |
| | $ | 271 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 405 |
| | 375 |
| | 341 |
|
| Amortization of debt issuance costs and premium/discounts | 12 |
| | 13 |
| | 13 |
|
| Deferred income taxes and investment tax credits, net | 80 |
| | 88 |
| | 171 |
|
| Other | 7 |
| | 11 |
| | — |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | 11 |
| | — |
| | (7 | ) |
| Inventories | 2 |
| | 8 |
| | (1 | ) |
| Accounts and wages payable | (19 | ) | | (13 | ) | | 19 |
|
| Taxes accrued | 21 |
| | (13 | ) | | 18 |
|
| Regulatory assets and liabilities | 155 |
| | 1 |
| | 16 |
|
| Assets, other | (23 | ) | | (1 | ) | | (2 | ) |
| Liabilities, other | (5 | ) | | (92 | ) | | 3 |
|
| Pension and other postretirement benefits | (30 | ) | | (25 | ) | | (14 | ) |
| Net cash provided by operating activities | 962 |
| | 659 |
| | 828 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,208 | ) | | (1,258 | ) | | (1,076 | ) |
| Other | 3 |
| | 10 |
| | 6 |
|
| Net cash used in investing activities | (1,205 | ) | | (1,248 | ) | | (1,070 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | (19 | ) | | 10 |
| | 11 |
|
| Maturities of long-term debt | — |
| | (457 | ) | | (250 | ) |
| Issuances of long-term debt | 299 |
| | 929 |
| | 496 |
|
| Debt issuance costs | (4 | ) | | (9 | ) | | (6 | ) |
| Capital contribution from parent | 15 |
| | 160 |
| | 8 |
|
| Other | — |
| | (2 | ) | | (1 | ) |
| Net cash provided by financing activities | 288 |
| | 628 |
| | 255 |
|
| Net change in cash, cash equivalents, and restricted cash | 45 |
| | 39 |
| | 13 |
|
| Cash, cash equivalents, and restricted cash at beginning of year | 80 |
| | 41 |
| | 28 |
|
| Cash, cash equivalents, and restricted cash at end of year | $ | 125 |
| | $ | 80 |
| | $ | 41 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $8, $7, and $4 capitalized, respectively) | $ | 127 |
| | $ | 144 |
| | $ | 139 |
|
| Income taxes, net | 4 |
| | 28 |
| | (22 | ) |
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 341 |
| | 318 |
| | 292 |
|
| Amortization of debt issuance costs and premium/discounts | 13 |
| | 14 |
| | 14 |
|
| Deferred income taxes and investment tax credits, net | 171 |
| | 154 |
| | 221 |
|
| Other | — |
| | (1 | ) | | (14 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | (7 | ) | | (72 | ) | | 16 |
|
| Inventories | (1 | ) | | 15 |
| | 25 |
|
| Accounts and wages payable | 19 |
| | 12 |
| | 37 |
|
| Taxes accrued | 18 |
| | 1 |
| | (2 | ) |
| Regulatory assets and liabilities | 16 |
| | 120 |
| | (26 | ) |
| Assets, other | (15 | ) | | (3 | ) | | 17 |
|
| Liabilities, other | 3 |
| | (5 | ) | | (27 | ) |
| Pension and other postretirement benefits | (14 | ) | | (8 | ) | | (4 | ) |
| Counterparty collateral, net | — |
| | 3 |
| | (3 | ) |
| Net cash provided by operating activities | 815 |
| | 803 |
| | 763 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,076 | ) | | (924 | ) | | (918 | ) |
| Other | 6 |
| | 6 |
| | 5 |
|
| Net cash used in investing activities | (1,070 | ) | | (918 | ) | | (913 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | — |
| | (110 | ) | | — |
|
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 11 |
| | 51 |
| | (32 | ) |
| Money pool borrowings, net | — |
| | — |
| | (15 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (250 | ) | | (129 | ) | | — |
|
| Issuances of long-term debt | 496 |
| | 240 |
| | 248 |
|
| Capital issuance costs | (6 | ) | | (4 | ) | | (3 | ) |
| Capital contribution from parent | 8 |
| | — |
| | 25 |
|
| Other | (1 | ) | | (1 | ) | | — |
|
| Net cash provided by financing activities | 255 |
| | 44 |
| | 220 |
|
| Net change in cash and cash equivalents | — |
| | (71 | ) | | 70 |
|
| Cash and cash equivalents at beginning of year | — |
| | 71 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | — |
| | $ | — |
| | $ | 71 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $4, $3, and $5 capitalized, respectively) | $ | 139 |
| | $ | 127 |
| | $ | 120 |
|
| Income taxes, net | (22 | ) | | 8 |
| | (113 | ) |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2017 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Other Paid-in Capital |
| |
| |
|
| Beginning of year | 2,173 |
| | 2,013 |
| | 2,005 |
|
| Capital contribution from parent | 15 |
| | 160 |
| | 8 |
|
| Other paid-in capital, end of year | 2,188 |
| | 2,173 |
| | 2,013 |
|
| | | | | | |
| Preferred Stock | 62 |
| | 62 |
| | 62 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,539 |
| | 1,235 |
| | 967 |
|
| Net income | 346 |
| | 307 |
| | 271 |
|
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,882 |
| | 1,539 |
| | 1,235 |
|
| | | | | | |
| Total Shareholders’ Equity | $ | 4,132 |
| | $ | 3,774 |
| | $ | 3,310 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Other Paid-in Capital |
| |
| |
|
| Beginning of year | 2,005 |
| | 2,005 |
| | 1,980 |
|
| Capital contribution from parent | 8 |
| | — |
| | 25 |
|
| Other paid-in capital, end of year | 2,013 |
| | 2,005 |
| | 2,005 |
|
| | | | | | |
| Preferred Stock | 62 |
| | 62 |
| | 62 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 967 |
| | 825 |
| | 611 |
|
| Net income | 271 |
| | 255 |
| | 217 |
|
| Common stock dividends | — |
| | (110 | ) | | — |
|
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,235 |
| | 967 |
| | 825 |
|
| | | | | | |
| Accumulated Other Comprehensive Income: | | | | | |
| Deferred retirement benefit costs, beginning of year | — |
| | 5 |
| | 8 |
|
| Change in deferred retirement benefit costs | — |
| | (5 | ) | | (3 | ) |
| Deferred retirement benefit costs, end of year | — |
| | — |
| | 5 |
|
| Total accumulated other comprehensive income, end of year | — |
| | — |
| | 5 |
|
| | | | | | |
| Total Shareholders’ Equity | $ | 3,310 |
| | $ | 3,034 |
| | $ | 2,897 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 20172019
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, 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. Ameren’s principal subsidiaries are listed below, including Ameren Missouri, Ameren Illinois, and ATXI.below. Ameren also has other subsidiaries that conduct other activities, such as the provision ofproviding shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise.
Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri. Ameren Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri, which includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 0.1 million customers.
Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois. Ameren Illinois was incorporated in Illinois in 1923 and is the successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to a 40,00043,700 square mile area in central and southern Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 0.8 million customers.
| |
| • | Ameren Transmission Company of Illinois, doing business as ATXI, operates a FERC rate-regulated electric transmission business in the MISO. ATXI was incorporated in Illinois in 2006. ATXI is constructing the Illinois Rivers project, a MISO-approved electric transmission project, and 8 of its 9 line segments have been completed and placed in service as of December 31, 2018. ATXI operates the Spoon River project and the Mark Twain project, which were placed in service in February 2018 and December 2019, respectively. |
ATXI operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and placed the Spoon River project in service in February 2018.
Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated. eliminated, except as disclosed inNote 13 – Related-party Transactions. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated. Unless otherwise stated, these notes to the financial statements exclude discontinued operations for all periods presented.
As of December 31, 2017 and December 31, 2016, Ameren had unconsolidated variable interests as a limited partner in various equity method investments totaling $17 million and $9 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly impact the activities of these variable interest entities. As of December 31, 2017, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $17 million plus associated outstanding funding commitments of $20 million.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are 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.
Regulation
WeOur customer rates are regulated by the MoPSC, the ICC, and the FERC. We defer certain costs as assets pursuant to actions of rate regulators or because of expectations that we will be able to recover such costs in future rates charged to customers. We also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. Ameren Missouri and Ameren Illinois have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs without a traditional regulatory rate review.
In Ameren Missouri’s and Ameren Illinois’ natural gas businesses, changes in natural gas costs are reflected in billings to their respective customers through PGA clauses. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period.
Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year, without a traditional rate proceeding, for a pass-through to customers of 95% of the variance in net energy costs from the amount set in base rates, subject to MoPSC prudence review. The difference between the actual amounts incurred for these items and the amounts recovered from Ameren Missouri customers’ base rates is deferred as a regulatory asset or liability. The deferred amounts are either billed or refunded to electric customers in a subsequent period.
In Ameren Illinois’ electric distribution business, changes in purchased power and transmission service costs are reflected in billings to its customers through pass-through rate-adjustment clauses. The difference between actual purchased power and transmission service costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period.
In addition to the rate-adjustment mechanisms discussed above, Ameren Missouri and Ameren Illinois have approvals from rate regulators to use other cost recovery mechanisms. Ameren Missouri has a pension and postretirement benefit cost tracker, an uncertain tax positions tracker, a renewable energy standards cost tracker, a solar rebate program tracker, and the MEEIA energy-efficiency rider. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois participates in performance-based formula ratemaking frameworks established pursuant to the IEIMA and the FEJA for its electric distribution business and its electric energy-efficiency investments. Ameren Illinois also has environmental cost riders, an asbestos-related litigation rider, natural gas energy-efficiency rider, a QIP rider, a VBA rider, and a bad debt rider. See Note 2 – Rate and Regulatory Matters for additional information on theour regulatory frameworks, regulatory recovery mechanisms, and regulatory assets and liabilities recorded at December 31, 20172019 and 2016.2018.
The Ameren Illinois asbestos-related litigation rider includes a trust fund. At December 31, 2017 and 2016,We continually assess the trust fund balancerecoverability of $23 million and $22 million, respectively, was reflected in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets. This balanceour respective regulatory assets. Regulatory assets are charged to earnings when it is restricted only for the use of funding certain asbestos-related claims. The rider is subject to the following terms: 90% of the cash expenditures in excess of the amount included in base electric rates is tono longer probable that such amounts will be recovered fromthrough future revenues. To the trust fund. If cash expendituresextent that reductions in customers’ rates or refunds to customers related to regulatory liabilities are less thanno longer probable, the amount in base rates, Ameren Illinois will contribute 90% of the differenceamounts are credited to the trust fund.earnings.
Cash, and Cash Equivalents, and Restricted Cash
Cash and cash equivalents include cash on hand and temporaryshort-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash. See Note 15 – Supplemental Information for a reconciliation of cash, cash equivalents, and restricted cash
reported within the balance sheets and the statements of cash flows.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a bad debt rider that adjusts rates for net write-offs of customer accounts receivable above or below those being collected in rates.
Inventories
Inventories are recorded at the lower of weighted-average cost or net realizable value. Inventories are capitalized when purchased and then expensed as consumed or capitalized as property, plant, and equipment when installed, as appropriate. The following table presents a breakdownSee Note 15 – Supplemental Information for the components of inventories for each of the Ameren Companies at December 31, 2017 and 2016:
|
| | | | | | | | | | | | |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2017 | | | | | | |
Fuel(a) | | $ | 154 |
| | $ | — |
| | $ | 154 |
|
| Natural gas stored underground | | 8 |
| | 74 |
| | 82 |
|
| Materials, supplies, and other | | 226 |
| | 60 |
| | 286 |
|
| Total inventories | | $ | 388 |
| | $ | 134 |
| | $ | 522 |
|
| 2016 | | | | | | |
Fuel(a) | | $ | 172 |
| | $ | — |
| | $ | 172 |
|
| Natural gas stored underground | | 9 |
| | 73 |
| | 82 |
|
| Materials, supplies, and other | | 211 |
| | 62 |
| | 273 |
|
| Total inventories | | $ | 392 |
| | $ | 135 |
| | $ | 527 |
|
| |
(a) | Consists of coal, oil, and propane. |
inventories.
Property, Plant, and Equipment, Net
We capitalize the cost of additions to, and betterments of, units of property, plant, and equipment. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures includingare expensed as incurred. Beginning in 2020, maintenance expenses related to scheduled Callaway nuclear refueling and maintenance outages, arewhich were previously expensed as incurred.incurred, are deferred and amortized over approximately 18 months. See Note 2 – Rate and Regulatory Matters for additional information. When units of depreciable property are retired, the original costs, lessand the associated removal cost, net of salvage, values, are charged to accumulated depreciation. If environmental expenditures are related to assets currently in use, as in the case of the installation of pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset. See Asset Retirement Obligations section below and Note 3 – Property, Plant, and Equipment, Net for additional information.
Ameren Missouri’s cost of nuclear fuel is capitalized as a part of “Property, Plant, and Equipment, Net” on the balance sheet and then amortized to “Operating Expenses – Fuel” in the statement of income on a unit-of-production basis.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The composite rates include a provision for the estimated removal cost of property, plant, and equipment retired from service, net of salvage. The provision for depreciation for the Ameren Companies in 2017, 2016,2019, 2018, and 20152017 ranged from 3% to 4% of the average depreciable cost. See Note 3 – Property, Plant, and Equipment, Net for additional information on estimated depreciable lives.
Allowance for Funds Used During Construction
WeAs a part of "Property, Plant, and Equipment, Net" on the balance sheet, we capitalize allowance for funds used during construction, orwhich is the cost of borrowed funds and the cost of equity funds (preferred and common shareholders’shareholders' equity) applicable to eligible rate-regulated construction expenditures,work in progress, in accordance with the utility industry’s accounting practice. practice and GAAP. The amount of allowance for funds used during construction is calculated using a FERC-prescribed formula based on a rate, which includes the average cost of short-term debt, the average cost of long-term debt, and the cost of equity funds. The portion attributable to borrowed funds is recorded as a reduction of "Interest Charges" on the statements of income. The portion attributable to equity funds is recorded within "Other Income, Net" on the statements of income. This accounting practice offsets the effect on earnings of the cost of financing during construction. See Note 15 – Supplemental Information for the amount of allowance for funds used during construction capitalized and the average rate applied to eligible construction work in progress.
Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing during construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The following table presents the annual allowance for funds used during construction debt and equity blended rates that were applied to construction projects in 2017, 2016, and 2015:
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | 7 | % | | 7 | % | | 7 | % |
| Ameren Illinois | 4 | % | | 5 | % | | 6 | % |
Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Ameren and Ameren Illinois had goodwill of $411 million at December 31, 20172019 and 2016.2018. Ameren has four4 reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois has three3 reporting units: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. Ameren Illinois Electric Distribution, Ameren Illinois
Natural Gas, and Ameren Illinois Transmission had goodwill of $238 million, $80 million, and $93 million, respectively, at December 31, 20172019 and 2016.2018. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 20172019 and 2016.2018.
Ameren and Ameren Illinois evaluate goodwill for impairment in each of their reporting units as of October 31 each year, or more frequently if events andoccur or circumstances change that would more likely than not reduce the fair value of their reporting units below their carrying amounts. To determine whether the fair value of a reporting unit is more likely than not greater than its carrying amount, Ameren and Ameren Illinois elect to perform either a qualitative assessment or to bypass the qualitative assessment and perform a quantitative test, on an annual basis. On December 31, 2016, due to a change in reporting units, Ameren and Ameren Illinois performed a quantitative test and determined that the estimated fair value of each reporting unit significantly exceeded its respective carrying value as of that date. Based on these results, test.
Ameren and Ameren Illinois elected to perform a qualitative assessment for their annual goodwill impairment test conducted as of October 31, 2017.
2019. As part of this qualitative assessment, Ameren and Ameren Illinois evaluated, among other things, macroeconomic conditions, industry and market considerations such as observable industry market multiples, regulatory frameworks, cost factors, overall financial performance, and entity-specific events. The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was more likely than not that the fair value of each reporting unit significantly exceeded its carrying value as of October 31, 2017,2019, resulting in no0 impairment of Ameren’s or Ameren Illinois’ goodwill. The following factors, among others, were considered by Ameren and Ameren Illinois when they assessed whether it was more likely than not that the fair value of each of their reporting units exceeded its carrying value as of October 31, 2017:
macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
pending regulatory rate review outcomes and projections of future regulatory rate review outcomes;
changes in laws and potential law changes;
observable industry market multiples;
achievement of IEIMA and FEJA performance metrics and the yield of 30-year United States Treasury bonds;
an unexpected further reduction in the FERC-allowed return on equity with respect to transmission services; and
projected operating results and cash flows.
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets to the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount by which the carrying value exceeds the estimated fair value of the assets. In the period in which we determine that an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its estimated fair value less cost to sell. We did not identify any events or changes in circumstances that indicated that the carrying value of long-lived assets may not be recoverable in 20172019 or 2018.
Variable Interest Entities
As of December 31, 2019, Ameren and 2016.Ameren Missouri had interests in unconsolidated variable interest entities that were established to construct wind generation facilities and, ultimately, sell those constructed facilities to Ameren Missouri. Neither Ameren nor Ameren Missouri are the primary beneficiary of these variable interest entities because neither has the power to direct matters that most significantly affect the entities’ activities, which include designing, financing, and constructing the wind generation facilities. As a result, these variable interest entities are not required to be consolidated. As of December 31, 2019, the maximum exposure to loss related to these variable interest entities was approximately $13 million, which primarily represents legal costs incurred. The risk of a loss was assessed to be remote and, accordingly, Ameren and Ameren Missouri have not recognized a liability associated with any portion of the maximum exposure to loss. See Note 2 – Rate and Regulatory Matters for additional information on the agreements to acquire these wind generation facilities.
As of December 31, 2019 and 2018, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, totaling $28 million and $22 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of December 31, 2019, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $28 million plus associated outstanding funding commitments of $35 million.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. See Note 14 – Commitments and Contingencies for additional information on liabilities for environmental costs.
Asset Retirement Obligations
We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs for accretion and based on changes in the estimated fair values of the obligations with a corresponding increase or decrease in the asset book value. Asset book values, reflected within “Property, Plant, and Equipment, Net” on the balance sheet, are depreciated over the remaining useful life of the related asset. Due to regulatory recovery, that depreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $26$18 million, $31$14 million, and $13$26 million for the years ended December 31, 2017, 2016,2019, 2018, and 2015,2017, respectively, which was deferred as a reduction to the net regulatory liability. The net regulatory liability also reflects deferrals of net realized and unrealized gains and losses within the nuclear decommissioning trust fund for the Callaway Energy
Center. The depreciation deferred to the regulatory asset at Ameren Illinois was immaterial in each respective period. Ameren and Ameren Missouri have a nuclear decommissioning trust fund for the decommissioning of the Callaway energy center. Net realized and unrealized gains and losses within the nuclear decommissioning trust fund are deferred as a regulatory liability. Uncertainties as to the probability, timing, or amount of cash expenditures associated with AROs affect our estimates of fair value. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with Ameren Missouri’s Callaway energy centerEnergy Center decommissioning, CCR facilities, and river structures. Also, Ameren, Ameren Missouri, and Ameren Illinois have recorded AROs for retirement costs associated with asbestos removal and the disposal of certain transformers. Asset removal costs that do not constitute legal obligations are classified as regulatory liabilities. See Note 215 – Rate and Regulatory Matters.
The following table providesSupplemental Information for a reconciliation of the beginning and ending carrying amount of AROsAROs.
Estimated funds collected from customers to pay for the years ended December 31, 2017future removal cost of property, plant, and 2016:equipment retired from service, net of salvage, represent a cost of removal regulatory liability. See the cost of removal regulatory liability balance in Note 2 – Rate and Regulatory Matters.
Company-owned Life Insurance |
| | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren | |
| Balance at December 31, 2015 | $ | 617 |
| | $ | 6 |
| | $ | 623 |
| |
| Liabilities incurred | 3 |
| | — |
| | 3 |
| |
| Liabilities settled | (2 | ) | | (a) |
| | (2 | ) | |
Accretion in 2016(b) | 25 |
| | (a) |
| | 25 |
| |
| Change in estimates | 1 |
| | — |
| | 1 |
| |
| Balance at December 31, 2016 | $ | 644 |
| (c) | $ | 6 |
| (d) | $ | 650 |
| (c) |
| Liabilities incurred | — |
| | — |
| | — |
| |
| Liabilities settled | (12 | ) | | (1 | ) | | (13 | ) | |
Accretion in 2017(b) | 26 |
| | (a) |
| | 26 |
| |
Change in estimates(e) | (18 | ) | | (1 | ) | | (19 | ) | |
| Balance at December 31, 2017 | $ | 640 |
| (c) | $ | 4 |
| (d) | $ | 644 |
| (c) |
| |
(b) | Ameren Missouri’s accretion expense was deferred as a decrease to regulatory liabilities. |
| |
(c) | Balance included $6 million and $15 million in “Other current liabilities” on the balance sheet as of December 31, 2017 and 2016, respectively.
|
| |
(d) | Included in “Other deferred credits and liabilities” on the balance sheet. |
| |
(e) | Ameren Missouri changed its fair value estimate primarily because of an extension of the remediation period of certain CCR storage facilities, an update to the decommissioning of the Callaway energy center to reflect the cost study and funding analysis filed with the MoPSC in 2017, and an increase in the assumed discount rate. |
Noncontrolling Interests
Ameren and Ameren Illinois have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of December 31, 2017 and 2016, Ameren’s noncontrolling interests included2019, the preferred stockcash surrender value of company-owned life insurance at Ameren Missouri and Ameren Illinois was $264 million (December 31, 2018 – $244 million) and $123 million (December 31, 2018 – $122 million), respectively, while total borrowings against the policies were $114 million (December 31, 2018 – $113 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets. The net cash surrender value of Ameren’s company-owned life insurance is affected by the investment performance of a separate account in which Ameren holds a beneficial interest.
Operating RevenueRevenues
The Ameren CompaniesWe record operating revenuerevenues from contracts with customers for various electric orand natural gas serviceservices, which primarily consist of retail distribution, electric transmission, and off-system arrangements. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price.
Electric and natural gas retail distribution revenues are earned when itthe commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service renderedprovided but unbilled at the end of each accounting period.
Ameren Illinois participates inElectric transmission revenues are earned as electric transmission services are provided.
Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the performance-based formula ratemaking framework pursuantsale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. MISO-related capacity and ancillary service revenues and wholesale bilateral capacity revenues are earned as services are provided.
Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers are equal to the IEIMAamounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the FEJA. In addition, Ameren Illinois’end of each accounting period. Customers are billed at least monthly, and ATXI’s electric transmission service operatingpayments are due less than one month after goods and/or services are provided. See Note 16 – Segment Information for disaggregated revenue information.
For certain regulatory recovery mechanisms that are alternative revenue programs rather than revenues from contracts with customers, we recognize revenues that have been authorized for rate recovery, are regulated by the FERC. The provisionsobjectively determinable and probable of the IEIMArecovery, and the FERC’s electric transmission formula rate framework provide for annual reconciliations of the electric distribution and electric transmission service revenue requirements necessaryare expected to reflect the actual recoverable costs incurred in a given year with the revenue requirements in customer rates for that year, including an allowed return on equity. In each of those electric jurisdictions, if the current year’s revenue requirement varies from the amountbe collected from customers an adjustment is made to electric operatingwithin two years from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, the MEEIA, and the VBA. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to a regulatory asset or liabilityalternative revenue program revenues.
As of December 31, 2019 and 2018, our remaining performance obligations were immaterial. The Ameren Companies elected not to reflect that year’s actual revenue requirement. The regulatory balance is then collected from, or refunded to, customers within two years. See Note 2 – Rate and Regulatory Matters for information regarding Ameren Illinois’ revenue requirement reconciliation pursuantdisclose the aggregate amount of the transaction price allocated to the IEIMA.performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, Ameren Missouri, and Ameren Illinois using settlement information provided by the MISO. Ameren Missouri records these purchase and sale transactions on a net hourly position. Ameren Missouri records net purchases in a single hour in “Operating Expenses – Purchased power” and net sales in a single hour in “Operating Revenues – Electric” in its statement of income. Ameren Illinois records net purchases in “Operating Expenses – Purchased power” in its statement of
income to reflect all of its MISO transactions relating to the procurement of power for its customers. On occasion, Ameren Missouri’s and Ameren Illinois’ prior-period transactions will be resettled outside the routine settlement process because of a change in the MISO’s tariff or a material interpretation thereof. In these cases, Ameren Missouri and Ameren Illinois recognize revenues and expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated. Revenues are recognized once the resettlement amount is received. There were no0 material MISO resettlements in 2017, 2016,2019, 2018, or 2015.
Nuclear Fuel
Ameren Missouri’s cost of nuclear fuel is capitalized and then amortized to fuel expense on a unit-of-production basis. The cost is charged to “Operating Expenses – Fuel” in the statement of income.2017.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date based on the fair value of the award, net of an assumed forfeiture rate. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite vesting period. See Note 11 – Stock-based Compensation for additional information.
Excise Taxes
Ameren Missouri and Ameren Illinois collect from their customers certain excise taxes that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business. They are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas,” and “Operating Expenses – Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes for electric service in Illinois are levied on customers and are therefore not included in Ameren Illinois’ revenues and expenses. The following table presents the excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas,” and “Operating Expenses – Taxes other than income taxes” for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 153 |
| | $ | 151 |
| | $ | 156 |
|
| Ameren Illinois | 57 |
| | 57 |
| | 57 |
|
| Ameren | $ | 210 |
| | $ | 208 |
| | $ | 213 |
|
Unamortized Debt Discounts, Premiums, and Issuance Costs
Long-term debt discounts, premiums, and issuance costs are amortized over the lives of the related issuances. Credit agreement fees are amortized over the term of the agreement.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We expect that regulators will reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in certain deferred tax liabilities that were recorded because of decreases in the statutory rate have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery through future customer rates of tax benefits related to the equity component of allowance for funds used during construction, as well as the effects of tax rate increases. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes is recorded as a regulatory asset or liability on the balance sheet and will be collected from, or refunded to, customers. For deferred tax balances not included in rate base, the revaluation of deferred taxes is recorded as an adjustment to income tax expense on the income statement. See Note 12 – Income Taxes for further information regarding both the revaluation of deferred taxes related to the TCJA.TCJA and Missouri and Illinois state corporate income tax rate changes.
Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren (parent) that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax using a stand-alone calculation, which is similar to that whichwhat would be owed or refunded had the party been separately subject to tax without considering the impact of consolidation. Any net benefit attributable to Ameren (parent) is reallocated to the other parties. This reallocation is treated as a capital contribution to the party receiving the benefit. See Note 13 – Related-party Transactions for information regarding capital contributions under the tax allocation agreement.
Earnings per Share
Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the potential dilution that would occur if certain stock-based performance share units were settled. The number of performance share units assumed to be settled was 1.6 million, 0.8 million, and 1.0 million for the years ended December 31, 2017, 2016, and 2015, respectively. There were no potentially dilutive securities excluded from the diluted earnings per share calculations for the years ended December 31, 2017, 2016, and 2015.
Divestiture Transactions and Discontinued Operations
In December 2013 and January 2014, Ameren completed the divestiture of New AER and certain other assets. All matters related to the final tax basis of New AER and the related tax benefit resulting from its divestiture were resolved with the completion of the IRS audit of 2013. During 2015, based on the completion of the IRS audit of 2013, Ameren removed a reserve for unrecognized tax benefits of $53 million recorded in 2013 and recognized a tax benefit from discontinued operations. Ameren also paid $25 million and concluded its obligations with New AER.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance, as well as guidance issued but not yet adopted, that could affect the Ameren Companies.
Revenue from Contracts with Customers
In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The underlying principle of the guidance is that an entity will recognize revenue for the transfer of promised goods or services to customers at an amount that the entity expects to be entitled to receive in exchange for those goods or services. The guidance requires additional disclosures to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, as well as separate presentation of alternative revenue programs on the income statement. Entities can apply the guidance to each reporting period presented (the full retrospective method), or they can record a cumulative effect adjustment to retained earnings in the period of initial adoption (the modified retrospective method).
We have completed the evaluation of our contracts. Adoption of this guidance will not result in material changes to the amount or timing of revenue recognition. We will apply the guidance using the full retrospective method. We will include disaggregated revenue disclosures by segment and customer class in the combined notes to the financial statements. This guidance will be effective for the Ameren Companies for the first quarter of 2018.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In March 2017, the FASB issued authoritative guidance that requires an entity to report, including on a retrospective basis, the non-service cost or income components of net benefit cost separately from the service cost component and outside of operating income. Our adoption of this guidance will result in the reclassification of 2017 net benefit income of $44 million, $22 million, and $10 million, currently presented as a reduction of "Other operations and maintenance expense," on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income. These amounts will be presented outside of operating income. Similarly, 2016 net benefit income of $55 million, $18 million, and $24 million, currently presented as a reduction of "Other operations and maintenance expense" on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income, will also be reclassified and presented outside of operating income.
The guidance also permits an entity to capitalize only the service cost component as part of an asset, such as inventory or property, plant, and equipment, on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization. This change in the capitalization of net benefit costs is not expected to affect our ability to recover total net benefit cost through customer rates. This guidance will be effective for2019, the Ameren Companies in the first quarter of 2018.adopted authoritative accounting guidance on leases. See Note 1015 – Retirement BenefitsSupplemental Information for the componentsadditional information.
Measurement of net benefit cost.
Restricted Cash
In November 2016, the FASB issued authoritative guidance that requires restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shownCredit Losses on the statement of cash flows. We are currently assessing the impacts of this guidance on our statements of cash flows and disclosures. The guidance will be effective for the Ameren Companies in the first quarter of 2018, and requires changes to be applied retrospectively to each period presented.
Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued authoritative guidance that specifies the classification and presentation of certain cash flow items to reduce diversity in practice. This guidance will be effective for the Ameren Companies in the first quarter of 2018, and requires changes to be applied retrospectively. For Ameren and Ameren Illinois, the adoption of this guidance will result in the retrospective reclassification from operating activities to financing activities of $7 million of bond premiums received in 2016.
Financial Instruments – Recognition and Measurement, and Credit Losses
In January 2016, the FASB issued authoritative guidance that addressed certain aspects of recognition, measurement, presentation and disclosure of financial instruments. This guidance requires an entity to measure equity investments, other than those accounted for under the equity method of accounting, at fair value and to recognize changes in fair value in net income. The adoption of this guidance will not have a material impact on our results of operations or financial position. The recognition, measurement, and disclosure guidance will be effective for the Ameren Companies in the first quarter of 2018. The guidance requires changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date.
In June 2016, the FASB issued authoritative guidance that requires an entity to recognize an allowance for financial instruments that reflects its current estimate of credit losses expected to be incurred over the life of the financial instruments. The guidance requires an entity to measure expected credit losses using relevant information about past events, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures. The credit lossThis guidance will be effective for the Ameren Companies in the first quarter of 2020. It requires2020, and will require changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date. The adoption of this guidance will not have a significant impact on the Ameren Companies’ financial statements.
LeasesFair Value Measurement Disclosures
In February 2016,August 2018, the FASB issued authoritative guidance that requires an entity to recognize assets and liabilities arising from all leases with a term greater than one year. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend on its classification as a finance lease or operating lease. The guidance also requires additional disclosures to enable users of financial statements to understand the amount, timing, and uncertainty of cash flows arising from leases. This guidance will affect the Ameren Companies’ financial position by increasing the assets and liabilities recorded relating to their operating leases, which will be recognized and measured at the beginning of the earliest period presented. Other arrangements not previously accountedaffects disclosure requirements for as leases may be required to be accounted for as leases; these arrangements would similarly result in increases to assets and liabilities recorded. We are currently assessing our arrangements to determine those that are within the scope of this guidance. We are also
assessing the impacts of this guidance for effects on our results of operations, cash flows, and disclosures.fair value measurements. This guidance will be effective for the Ameren Companies in the first quarter of 2019. See Note 14 – Commitments and Contingencies for additional information on our leases.2020.
Reclassification of Certain Tax Effects from Accumulated OCI
Defined Benefit Plan Disclosures
In FebruaryAugust 2018, the FASB issued authoritative guidance allowing a reclassification from accumulated OCIthat affects disclosure requirements for defined benefit plans. This guidance will be effective for the Ameren Companies in the fourth quarter of 2020, and will require changes to retained earnings for stranded tax effects resulting from the TCJA. This optional reclassification can be applied retrospectively to December 31, 2017, or in theeach period of adoption. We are currently assessing whether we will elect to perform such a reclassification and the potential impact.presented.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of our regulatory frameworks and significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.
Regulatory Frameworks
Missouri
March 2017 Electric Rate OrderThe MoPSC regulates rates and other matters for Ameren Missouri's electric service and natural gas distribution businesses. The rates Ameren Missouri charges customers for these services are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a historical test year and the allowed ROE established in the review.
In March 2017,Ameren Missouri has recovery mechanisms, including the RESRAM, FAC, MEEIA, PGA, DCA, and ISRS, that allow customer rates to be adjusted without a traditional regulatory rate review. These rate-adjustment mechanisms, along with the PISA, each described in more detail below, mitigate the effects of regulatory lag. Ameren Missouri also employs other recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain income tax position tracker, a tracker on certain excess deferred income taxes, a renewable energy standard cost tracker, and a solar rebate program cost tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability. The difference will be reflected in base rates in a subsequent MoPSC rate order. Ameren Missouri’s cost recovery under any of its recovery mechanisms is subject to MoPSC prudence reviews.
The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense and a return at the applicable WACC on investments in certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC, with all approved PISA deferrals added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense and a return at the applicable WACC for investments in renewable generation plant placed in service and not recovered under the PISA. The deferrals are a regulatory asset until they are included in customer rates and collected in a subsequent period. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Ameren Missouri recognizes the cost of debt on PISA deferrals in revenue, instead of using the applicable WACC, with the difference recognized in revenues when recovery of such deferrals is reflected in customer rates. Under Missouri law, as a result of the PISA election, additional provisions apply to Ameren Missouri, including limitations on electric customer rate increases. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the2.85%rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review would be subject to the rate cap. Any deferred overages approved for recovery would be recovered in a manner consistent with costs recovered under the 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. Customer rates for Ameren Missouri’s electric service did not exceed the cap in 2019. Both the rate increase limitation and the PISA are effective through December 2023. Missouri law provides for the ability to use the PISA, if Ameren Missouri requests and receives MoPSC approval for extension, through December 2028.
The RESRAM permits Ameren Missouri to recover or refund, through customer rates, the difference between the cost of compliance with Missouri’s renewable energy standard and the amount set in base rates. Customer rates are adjusted for the RESRAM on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. The difference between actual compliance costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. RESRAM regulatory assets earn carrying costs at short-term interest rates. The RESRAM permits Ameren Missouri to recover investments in wind generation and other renewables, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism.
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 regulatory rate review, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense. The difference between actual net energy costs and costs billed to
customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. FAC regulatory assets earn carrying costs at short-term interest rates. Ameren Missouri’s base rates for electric service are required to be reset at least every four years to allow for continued use of the FAC.
The MEEIA permits Ameren Missouri to recover customer energy-efficiency program costs, the related lost electric margins, and any performance incentive through the MEEIA without a traditional regulatory rate review. MEEIA assets earn carrying costs at short-term interest rates.
Ameren Missouri is a member of the MISO, and its transmission rate is calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets 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 actual historical cost from the prior calendar year. 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.
The PGA allows Ameren Missouri to recover prudently incurred costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The DCA ensures recoverability of the natural gas delivery service revenue requirement that is dependent on sales volume for nearly all customers. The DCA allows Ameren Missouri to adjust natural gas delivery service rates without a traditional regulatory rate review when changes occur in sales volumes from those volumes approved by the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016the previous regulatory rate review. The order resulteddifference between actual gas delivery service revenues billed to customers and revenues approved by the MoPSC in a $3.4 billiongiven period is deferred as a regulatory asset or liability. DCA regulatory assets earn carrying costs at short-term interest rates. The deferred amount is either billed or refunded to customers in a subsequent period. In addition, the ISRS permits certain prudently incurred natural gas infrastructure replacement costs to be recovered from customers on a more timely basis between regulatory rate reviews. The ROE currently used by Ameren Missouri for purposes of the ISRS tariff is 9.725%.
Illinois
The ICC regulates rates and other matters for Ameren Illinois' electric distribution service and natural gas distribution businesses. The rates Ameren Illinois charges customers for electric distribution service are calculated under a performance-based formula ratemaking framework. The rates Ameren Illinois charges customers for natural gas distribution service are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a future test year and an allowed ROE established in the review.
Ameren Illinois’ election to use the electric distribution service performance-based formula ratemaking framework allowed by state law, described below, permits Ameren Illinois to adjust customer rates to recover the cost of electric distribution service on an annual basis. Ameren Illinois electric distribution service also has other cost recovery mechanisms in place that allow customer rates to be adjusted without a traditional regulatory rate review. Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power procurement and transmission services incurred on behalf of its customers, renewable energy credit compliance, 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. These pass-through costs do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
Ameren Illinois’ electric distribution service performance-based formula ratemaking framework allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the year. In addition, Ameren Illinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for both its electric distribution service and its electric energy-efficiency investments, the revenue requirements are based on recoverable costs, year-end rate base, a capital structure of up to and including 50% common equity, and earn a return at the applicable WACC. The ROE component of the applicable WACC is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points and any performance-related basis point adjustments, described in more detail below. Therefore, Ameren Illinois’ annual ROE for its electric distribution business is directly correlated to the yields on such bonds. In addition, regulatory assets applicable to formula ratemaking for both electric distribution service and electric energy-efficiency investments earn a return at the applicable WACC. However, Ameren Illinois recognizes the cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates.
Ameren Illinois electric distribution service business is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed ROE 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 ROE penalties up to 38 basis points in each year from 2020 through 2022, if these performance standards are not met. The allowed ROE on energy-efficiency investments can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings goals. Any adjustments to the allowed ROE for energy-efficiency investments will depend on annual performance of a historical period relative to energy savings goals. In 2019, 2018, and 2017, there were no material performance-related basis point adjustments.
Ameren Illinois’ natural gas distribution business has recovery mechanisms, including the QIP, PGA, and VBA, that allow customer rates to be adjusted without a traditional regulatory rate review. These rate-adjustment mechanisms, described in more detail below, mitigate the effects of regulatory lag. Ameren Illinois employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expenses and invested capital taxes not recovered in base rates. Pass-through costs under the cost recovery mechanisms do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
The QIP rider provides Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that are placed in service between regulatory rate reviews. Infrastructure investments under the QIP rider earn a return at the applicable WACC. Eligible natural gas investments include projects to improve safety and reliability and modernization investments, such as smart meters. The deferrals are a regulatory asset until they are included in customer rates in a subsequent period. Recovery of the regulatory asset 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 investments. Without legislative action, the QIP rider will expire in December 2023.
The PGA allows Ameren Illinois to recover prudently incurred costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review. These pass-through purchased gas costs do not affect Ameren Illinois natural gas margins, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The VBA ensures recoverability of the natural gas distribution service revenue requirement that is dependent on sales volumes for residential and small nonresidential customers. 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 those volumes approved by the ICC in a previous regulatory rate review. The difference between allowed sales revenues and amounts billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is collected from, or refunded to, customers in a subsequent period. VBA regulatory assets earn carrying costs at short-term interest rates.
Federal
The FERC regulates rates and other matters for Ameren Illinois' transmission business and ATXI. Both Ameren Illinois and ATXI are members of the MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets 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. The formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which wasreflects the actual recoverable costs incurred and the 13-month average rate base for a $92 million increasegiven year, with the revenue requirement in customer rates, including an allowed ROE. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is collected from, or refunded to, customers within two years from the end of the year. FERC revenue reconciliation adjustment regulatory assets earn carrying costs at each company’s short-term interest rates, while each company incurs interest at a FERC-prescribed rate on related regulatory liabilities. In addition, the FERC has approved transmission rate incentives, including a 50 basis point incentive adder to the allowed base ROE for Ameren Illinois and ATXI for participation in an RTO, and an additional 50 basis point ROE incentive adder the Mark Twain project earns based on the unique nature of risks involved in the project.
Proceedings and Updates
Missouri
2019 Electric Service Regulatory Rate Review
In July 2019, Ameren Missouri filed a request with the MoPSC seeking approval to decrease its annual revenues for electric service by $1 million. In February 2020, Ameren Missouri, the MoPSC staff, the MoOPC, and certain intervenors filed a nonunanimous stipulation and agreement with the MoPSC to decrease Ameren Missouri’s annual revenue requirementrevenues for electric service compared withby $32 million. The remaining intervenor did not object to the prior revenue requirement established inagreement. The stipulation and agreement, which is subject to MoPSC approval, specified an allowed ROE range of 9.4% to 9.8%, but did not specify the MoPSC’s April 2015 electriccommon equity percentage or rate order.base. The new rates, base level of expenses,stipulation and amortizations became effective on April 1, 2017.
The order authorizedagreement includes the continued use of the FAC and the regulatory tracking mechanismstrackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standardsstandard compliance costs that the MoPSC previously authorized in earlier electric rate orders. These regulatory tracking mechanisms provideAmeren Missouri cannot predict whether the MoPSC will approve the stipulation and agreement or, if approved, whether any application for a baserehearing or appeal will be filed, or the outcome if so filed.
A decision by the MoPSC on the nonunanimous stipulation and agreement is expected by March 2020, with new rates effective as early as April 1, 2020. Ameren Missouri cannot predict the level of expenseany electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the requested regulatory recovery mechanisms will be approved, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.
The percentage of net energy cost variances from the amount set in base rates allowed to be recovered or refunded under the FAC and costs from services provided by affiliates are still being challenged by the MoOPC, and are expected to be addressed in a proceeding that would begin in March 2020. A MoPSC decision would be expected in the proceeding by the end of May 2020.If a change to the percentage of net energy cost variances from the amount set in base rates allowed to be recovered or refunded under the FAC is ordered by the MoPSC, the ordered percentage will be reflected in Ameren Missouri’s base electricthe FAC. If any investments or expenses are disallowed by the MoPSC, the effect on customer rates with differences between the base amount and the actual expenses incurredof such disallowances will be deferred as a regulatory asset liability and refunded to customers over a period of time determined in the next regulatory rate review.
Wind Generation Facilities and RESRAM
In May 2019, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 300-megawatt wind generation facility. In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to400-megawatt wind generation facility. These two agreements are subject to customary contract terms and conditions. The two build-transfer acquisitions collectively represent $1.2 billion of capital expenditures, are expected to be completed by the end of 2020, and would support Ameren Missouri’s compliance with the Missouri renewable energy standard. Both acquisitions have received all regulatory approvals, and both projects have received all applicable zoning approvals, have entered into RTO interconnection agreements, and have begun construction activities. The following table provides information with respect to each build-transfer agreement:
|
| | | | |
| | Up-to 400-Megawatt Facility | | Up-to 300-Megawatt Facility |
| Build-transfer agreement date | | April 2018 | | May 2019 |
| Wind facility developer | | Terra-Gen, LLC | | Invenergy Renewables, LLC |
| Location | | Northeastern Missouri | | Northwestern Missouri |
| Status of certificate of convenience and necessity from the MoPSC | | Approved October 2018 | | Approved August 2019 |
| Status of final interconnection costs | | Received July 2019 | | Received July 2019 |
| Status of RTO transmission interconnection agreement | | Executed August 2019 | | Executed October 2019 |
| Status of FERC approval | | Received December 2018 | | Received October 2019 |
| Expected completion date | | By the end of 2020 | | By the end of 2020 |
In February 2020, the developers of the wind generation facilities received notice from the wind turbine supplier of potential disruptions in its manufacturing, transport, and/or liability. Excluding cost reductionsimport/export activities resulting from the international public health emergency associated with reduced sales volumes, the base level of net energynovel coronavirus (COVID-19). The developers notified Ameren Missouri that their performance might be delayed as a result. At this time, Ameren Missouri and the developers are unable to estimate the impact to each project, including the project schedule and contracted megawatts.
In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, a 157-megawatt wind generation facility. In July 2019, Ameren Missouri and the developer mutually agreed to terminate the project due to unacceptable interconnection costs, decreased by $54 million fromwhich made the base level establishedproject uneconomic and not in the MoPSC’s April 2015 electric rate order. Changes in amortizations andbest interest of Ameren Missouri’s customers. Abandonment costs incurred as a result of terminating the base level of expenses forproject were immaterial to Ameren Missouri.
In January 2019, the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC’s April 2015 electric rate order.
MEEIA
In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a stipulation and agreement among Ameren Missouri, the MoPSC staff, and the MoOPC. Ameren Missouri will collect the performance incentive over a two-year period that began in February 2017.
In November 2015, the MoPSC issued an order regarding the determination of a certain input used to calculate the performance incentive. Ameren MissouriMoOPC filed an appeal of the order with the Missouri Court of Appeals, Western District.District, challenging the MoPSC’s December 2018 order allowing Ameren Missouri to recover, through the RESRAM, the 15% of depreciation expense and return at the applicable WACC not recovered under the PISA. In December 2016,October 2019, the Missouri Court of Appeals, Western District, upheld the MoPSC’s order. In November 2015 MoPSC order. Ameren Missouri then appealed that decision2019, the MoOPC filed a request for appeal of the MoPSC’s order to the Missouri Supreme Court. If the decision is overturned, Ameren Missouri would recognize an additional $9 million MEEIA 2013 performance incentive.Court, which was denied in February 2020.
The MEEIA 2016 program provided Ameren Missouri with a performance incentive to earn additional revenues by achieving certain customer energy-efficiency goals, including $27 million if 100% of the goals were achieved during the three-year period, with the potential to earn more if Ameren Missouri’s energy savings exceeded those goals. In September 2017, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings results for the first year of the MEEIA 2016 programs.
As a result of thisMoPSC orders issued in September 2017, October 2018, January 2019, and September 2019 related to performance incentives for the MEEIA 2013 and MEEIA 2016 programs, Ameren Missouri recognized revenues of $37 million and $11 million during 2019 and 2018, respectively.
Deferral of Maintenance Expenses Related to Scheduled Callaway Refueling and Maintenance Outages
In February 2020, the MoPSC issued an order approving a stipulation and in accordanceagreement allowing Ameren Missouri to defer and amortize maintenance expenses related to scheduled refueling and maintenance outages at its Callaway Energy Center.Beginning with revenue recognition guidance,the fall 2020 refueling and maintenance outage, Ameren Missouri will recognize $5 million of additional revenues indefer the first quarter of 2018 relatingmaintenance expenses incurred related to the MEEIA 2016 performance incentive.
MoPSC Federal Income Tax Proceeding
In February 2018, the MoPSC initiated proceedings to investigate how the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA should be reflected in rates paid by customers of Missouri’s regulated utilities, including rates paid by electrica refueling and natural gas customers of Ameren Missouri. At this time, Ameren Missouri is unable to predict the timing or the magnitude of any impact on its electric and natural gas rates that may result from the ultimate resolution of this matter.
ATXI’s Mark Twain Project
The Mark Twain project is a MISO-approved transmission line to be located in northeast Missouri with an expected investment of $250 million. In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with Ameren Missouri and an electric cooperative in northeast Missouri to locate almost all of the Mark Twain project on existing line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to begin construction in the second quarter of 2018 and to complete the project by the end of 2019.
Illinois
IEIMA & FEJA
Under a formula ratemaking framework effective through 2022, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. The formula ratemaking framework qualifiesmaintenance outage as an alternative revenue program under GAAP. Each year, Ameren Illinois records a regulatory asset orand amortize those expenses after completion of the outage. Maintenance expenses will be amortized over the period between refueling and maintenance outages, which is approximately 18 months.
2018 Natural Gas Delivery Service Regulatory Rate Review
In December 2018, Ameren Missouri filed a regulatory liability and a correspondingrequest with the MoPSC to increase or decrease to operatingits annual revenues for any differences betweennatural gas delivery service. In August 2019, the revenue requirement reflected in customerMoPSC issued an order approving a stipulation and agreement to decrease Ameren Missouri’s annual revenues for natural gas delivery service by$1 millionfrom rates for that year and its estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC. AsMoPSC in January 2011. The decrease in annual rates is based on an allowed ROE range of December 31, 2017, Ameren Illinois had recorded regulatory assets9.4% to 9.95% and a capital structure composed of $54 million and $24 million, including interest, to reflect its expected 2017 and its approved 2016 revenue requirement reconciliation adjustments, respectively. As of December 31, 2016, Ameren Illinois had recorded a $68 million regulatory asset to reflect its approved 2015 revenue requirement reconciliation adjustment,52.0% common equity, which was collected, with interest,Ameren Missouri’s capital structure as of May 31, 2019. This order permits the use of the DCA, as well as ISRS, which will be calculated using an allowed ROE of 9.725%. The order represents a $1 million increase to Ameren Missouri’s annual revenues for natural gas delivery service from customers during 2017.interim rates, which were approved by the MoPSC in December 2018. The new rates became effective September 1, 2019.
Illinois
Electric Distribution Service Rates
In December 2017,2019, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $17 $7 million decrease in Ameren Illinois’ electric deliverydistribution service revenue requirementrates beginning in January 2018.2020. This updateorder reflected an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, as well as an increase to include the 2016 revenue requirement reconciliation adjustment. The increases in the update filing were more than offset by a decrease for the conclusion of the 20152017 revenue requirement reconciliation adjustment, which was fully collected from customers in 2017,2019, consistent with the ICC’s December 2016November 2018 annual update filing order.
The FEJA revised certain portions of It also reflected an increase to the IEIMA, including extendingannual formula rate based on 2018 actual costs and expected net plant additions for 2019, and an increase to include the IEIMA formula ratemaking framework through 2022, and clarifying that a common equity ratio up to and including 50% is prudent. Beginning in 2017, the FEJA permitted Ameren Illinois to recover, within the following two years, its electric distribution2018 revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as 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 previous revenue recognition method resulted in more revenue during the third quarter and less revenue during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed the method it uses to recognize interim-period revenue. Ameren Illinois now recognizes revenue consistent with the timing of actual incurred electric distribution recoverable costs, and it recognizes revenue associated with the expected return on its rate base ratably over the year. The decoupling provisions of the FEJA do not expire at the end of 2022.reconciliation adjustment.
The FEJA allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. 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 monthly average yield 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. The FEJA increased the level of electric energy-efficiency saving targets through 2030. Electric Customer Energy-Efficiency Investments
In June 2017, pursuant to the FEJA,May 2019, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to establish the revenue requirement to be used for 2020 rates with the ICC an energy-efficiency plan for 2018 through 2021.ICC. In September 2017,November 2019, the ICC issued an order approving Ameren Illinois’ implementationthat approved 2020 electric customer energy-efficiency rates of the FEJA electric energy-efficiency savings targets and investments. Ameren Illinois plans to invest up to $99 $44 million per year in electric energy-efficiency programs , which represents an increase of $10 million from 2018 through 2021. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments will be collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework.2019 rates.
Income Tax Regulatory Mechanisms
In February 2018, the ICC granted Ameren Illinois’ request, filed in January 2018, to establish a rider to pass through to Ameren Illinois’ electric distribution customers the reduction in the federal statutory corporate income tax rate enacted under the TCJA and the return of excess deferred taxes, net of the increase in state income taxes enacted in July 2017. Ameren Illinois' electric distribution customers will receive up to an estimated $50 million per year through the rider beginning in the first quarter of 2018 and continuing through 2019. Absent
this rider, Ameren Illinois' electric distribution customers would not benefit from Ameren Illinois' reduced income tax liability until 2020 at which time the net reduction in income taxes would have been reflected in customer rates through the revenue reconciliation process.
In January 2018, the ICC initiated a proceeding to require that Ameren Illinois record a regulatory liability, beginning January 25, 2018, for the net amount of the difference between revenues billed under natural gas rates in effect, pursuant to Ameren Illinois’ most recent natural gas rate order, and the revenues that would have been billed had the state and federal tax rate changes been in effect. In February 2018, Ameren Illinois filed a response to the ICC seeking approval of a rider that calculates such differences, specifically by evaluating the return of excess deferred taxes and income taxes included in the revenue requirement prior to the reduction in the federal statutory corporate income tax rate enacted under the TCJA and the increase in state income taxes enacted in July 2017. Ameren Illinois’ natural gas customers may receive up to an estimated $16 million through the proposed rider, or through some other tariff approved by the ICC, over a one-year period beginning in May 2018.
2018 Natural Gas Delivery Service Regulatory Rate Review
In January 2018,February 2020, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49$102 million, which included an estimated $42$46 million of annual revenues that would otherwise be recovered under athe QIP riderand other riders. The request wasis based on a 10.3% return on common equity,10.5% allowed ROE, a capital structure composed of 50%54.1% common equity, and a rate base of $1.6 billion. The request reflects the reduction in the federal corporate income tax rate as a result of the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017.$2.1 billion. In an attempt to reduce regulatory lag, Ameren Illinois used a 20192021 future test year in this proceeding.
A decision by the ICC in this proceeding is required by December 2018,January 2021, with new rates expected to be effective in January 2019.February 2021. Ameren Illinois cannot predict the level of any delivery service rate changeschange the ICC may approve, nor whether any rate changeschange that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on investments when the rate changes go into effect.
ATXI’s Illinois Rivers ProjectQIP Prudence Review
In August 2017,March 2019, Ameren Illinois filed a request for an ICC prudence review of natural gas infrastructure investments recovered under the QIP rider during 2018. In November 2019, the Illinois Circuit CourtAttorney General's office challenged the recovery of capital investments, among other things, that were made during 2018, alleging that the amount of investments is excessive based on a comparison to historical investment levels. The Illinois Attorney General's office is not alleging imprudence or that the investments do not qualify for Edgar County dismissed several of ATXI’s condemnation cases related to one line segment in the Illinois Rivers project. The estimated line segment capital expenditure investment is approximately $85 million, of which $36 million was invested as of December 31, 2017. These cases had been filed to obtain easements and rights of way necessary to complete the line segment. The court found that required notice was not given to the relevant landowners during the underlying ICC proceeding.recovery. In November 2017, ATXI appealed this decision to 2019,
the Illinois Supreme Court. ATXI plans to complete the projectICC staff filed testimony that supports recovery of capital investments made during 2018. Ameren Illinois’ 2018 QIP rate recovery under review by the end of 2019; however, delays associated withICC is within the condemnation proceedings or an appeal arising from the order dismissing the Edgar County cases could delay the completion date. The other eight line segments of the Illinois Rivers project are not affectedrate increase limitations allowed by these proceedings.law. An ICC decision in this proceeding is expected by mid-2020.
Federal
FERC Complaint Cases
In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base return on common equityROE for FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a finalan order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015ROE to 10.32%, or a 10.82% total allowed return on common equityROE with the inclusion of a 50 basis point incentive adder for participation in an RTO.RTO, that was effective from late September 2016 forward. The September 2016 order also required customer refunds with interest, to be issued for that 15-month period. In 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the period November 2013 complaint case. The 10.82% total allowed return on common equity has been reflected in rates since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in theto February 2015, complaint case, discussed below.
Sincewhich were paid in 2017. With the maximum FERC-allowed refund period for the November 2013 complaint case ended in February 2015, another customer complaint case was filed in February 2015. MISO transmission owners subsequently filed a motion to dismiss the February 2015, complaint, as discussed below. The February 2015 complaint case seeksseeking a further reduction in the allowed base return on common equityROE for FERC-regulated transmission rate base under the MISO tariff. 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% total2016. In November 2019, the FERC issued an order addressing the November 2013 complaint case, which set the allowed return on equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. It would also require customerbase ROE at 9.88% and required refunds, with interest, for that 15-month period. A final FERCthe periods November 2013 to February 2015 and from late September 2016 forward. The 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.The timing of the issuance of the final order indismissed the February 2015 complaint case is uncertain for two reasons. First, while the FERC reestablishedcase.
As a quorum of commissioners in August 2017 after six months without a quorum, the FERC is under no deadline to issue a final order. Second, in the second quarter of 2017, the United States Court of Appeals for the District of
Columbia Circuit vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. Ameren is unable to predict the impactresult of the outcome of the United States Court of Appeals for the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time.
In September 2017, MISO transmission owners, includingNovember 2019 order, Ameren Missouri,and Ameren Illinois fully reduced their regulatory liabilities of $46 million and ATXI, filed a motion to dismiss$27 million, respectively, associated with the February 2015 complaint case with the FERC. The MISO transmission owners maintain that the February 2015 complaint was predicated on the premise that the now superseded 12.38% allowed base return on common equity was an unjust and unreasonable return and is therefore inapplicable given the current 10.32% allowed base return on common equity. The MISO transmission owners further maintain that the current 10.32% allowed base return on common equity has not been proven to be unjust and unreasonable based on information provided, including the base return on common equity methodology ranges set forth in the February 2015 complaint case and in the initial decision issued by an administrative law judge in June 2016. Additionally, the MISO transmission owners maintain that the February 2015 complaint should be dismissed because the approach utilized in the case to assert that a return on common equity was unjust and unreasonable was insufficient. That same approach was rejected by the United States Court of Appeals for the District of Columbia Circuit, as discussed above. FERC is under no deadline to issue an order on this motion.
case. As of December 31, 2017,2019, Ameren and Ameren Illinois had recorded current regulatory liabilities of $42$40 million and $25$23 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equityROEs in the initialNovember 2019 decision in the February 2015November 2013 complaint case. Ameren Missouri does not expect that aThe reduction in the FERC-allowed base return on common equity would beROE is not material to itsAmeren Missouri’s results of operations, financial position, or liquidity.
MISO Federal Income Tax Proceeding
In February 2018,December 2019, Ameren and the MISO transmission owners, with forward-looking rate formulas, including Ameren Missouri, Ameren Illinois, and ATXI, filed a requestrequests for rehearing with the FERC. Additionally, in December 2019, various parties filed requests for rehearing with the FERC, challenging the dismissal of the February 2015 complaint case.The FERC has not ruled on the merits of the rehearing requests and is under no deadline to allow revisionsdo so. The allowed base ROE for the 15-month period related to their 2018the February 2015 complaint case was 12.38%. Each 50 basis point reduction in the allowed base ROE for this period would reduce Ameren’s and Ameren Illinois’ net income by an estimated $10 million and $6 million, respectively.
In March 2019, the FERC issued separate Notices of Inquiry regarding its allowed base ROE policy and its transmission incentives policy. Initial comments were due by June 2019, and reply comments were due by late August 2019. The Notice of Inquiry addressing the FERC’s base ROE policy, among other things, broadened the ability to comment on the new methodology beyond electric utilities that are participants in the complaint cases. The transmission ratesincentives Notice of Inquiry was open for comment on the FERC’s transmission incentive policy, including incentive adders to reflect the base ROE. Ameren is unable to predict the ultimate impact of the reduction in federal income taxes enacted under the TCJA. If approved, Ameren Illinois and ATXI’s 2018 electric transmission rates would be reduced by $27 million and $23 million, respectively. AbsentNotices of Inquiry at this revision, the reduction in federal income taxes enacted under the TCJA would not be reflected in Ameren Illinois' and ATXI's electric transmission rates until 2020 through the revenue reconciliation process.time.
Combined Construction and Operating License
In 2008, Ameren Missouri filed an application with the NRC for a COL for a second nuclear unit at Ameren Missouri’s existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a second nuclear unit at its existing Callaway site, and the NRC suspended review of the COL application. Prior to suspending its efforts, Ameren Missouri had capitalized $69 million related to the project. Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway site. As a result of this decision, in 2015, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision for all of the previously capitalized COL costs. Ameren Missouri has withdrawn its COL application with the NRC.
Regulatory Assets and Liabilities
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, we defer certain costs as regulatory assets pursuant to actions of regulators or because we expect to recover such costs in rates charged to customers. We may also defer certain amounts as regulatory liabilities because of actions of regulators or because we expect that such amounts will be returned to customers in future rates. The following table presents our regulatory assets and regulatory liabilities at December 31, 20172019 and 2016: |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Current regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a)(b) | | $ | 47 |
| | $ | — |
| | $ | 47 |
| | | $ | 21 |
| | $ | — |
| | $ | 21 |
|
Under-recovered Illinois electric power costs(c) | | — |
| | — |
| | — |
| | | — |
| | 3 |
| | 3 |
|
Under-recovered PGA(c) | | 1 |
| | 13 |
| | 14 |
| | | — |
| | 4 |
| | 4 |
|
MTM derivative losses(d) | | 8 |
|
| 25 |
| | 33 |
| | | 9 |
| | 15 |
| | 24 |
|
Energy-efficiency riders(e) | | — |
| | — |
| | — |
| | | 5 |
| | — |
| | 5 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 24 |
| | 24 |
| | | — |
| | 68 |
| | 68 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 9 |
| | 10 |
| | | — |
| | 7 |
| | 13 |
|
VBA rider(a)(h) | | — |
| | 15 |
| | 15 |
| | | — |
| | 11 |
| | 11 |
|
2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Other | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
| Total current regulatory assets | | $ | 56 |
| | $ | 87 |
| | $ | 144 |
| | | $ | 35 |
| | $ | 108 |
| | $ | 149 |
|
| Noncurrent regulatory assets: | | | | | | | | | | | | | |
Pension and postretirement benefit costs(i) | | $ | 84 |
| | $ | 215 |
| | $ | 299 |
| | | $ | 175 |
| | $ | 319 |
| | $ | 494 |
|
Income taxes(j) | | 139 |
| | 56 |
| | 197 |
| | | 229 |
| | 1 |
| | 230 |
|
Uncertain tax positions tracker(a)(k) | | 5 |
| | — |
| | 5 |
| | | 7 |
| | — |
| | 7 |
|
ARO(l) | | — |
| | 1 |
| | 1 |
| | | — |
| | 3 |
| | 3 |
|
Callaway costs(a)(m) | | 25 |
| | — |
| | 25 |
| | | 29 |
| | — |
| | 29 |
|
Unamortized loss on reacquired debt(a)(n) | | 61 |
| | 49 |
| | 110 |
| | | 65 |
| | 59 |
| | 124 |
|
Environmental cost riders(o) | | — |
| | 173 |
| | 173 |
| | | — |
| | 196 |
| | 196 |
|
MTM derivative losses(d) | | 4 |
|
| 192 |
| | 196 |
|
|
| 9 |
| | 178 |
| | 187 |
|
Storm costs(a)(p) | | — |
| | 10 |
| | 10 |
| | | — |
| | 15 |
| | 15 |
|
Demand-side costs before the MEEIA implementation(a)(q) | | 11 |
| | — |
| | 11 |
| | | 18 |
| | — |
| | 18 |
|
Workers’ compensation claims(r) | | 5 |
| | 7 |
| | 12 |
| | | 6 |
| | 7 |
| | 13 |
|
Credit facilities fees(s) | | 3 |
| | — |
| | 3 |
| | | 4 |
| | — |
| | 4 |
|
Construction accounting for pollution control equipment(a)(t) | | 18 |
| | — |
| | 18 |
| | | 19 |
| | — |
| | 19 |
|
Solar rebate program(a)(u) | | 31 |
| | — |
| | 31 |
| | | 49 |
| | — |
| | 49 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 54 |
| | 54 |
| | | — |
| | 23 |
| | 23 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 16 |
| | 27 |
| | | — |
| | 8 |
| | 10 |
|
FEJA energy-efficiency riders(a)(v) | | — |
| | 41 |
| | 41 |
| | | — |
| | — |
| | — |
|
| Other | | 9 |
| | 8 |
| | 17 |
| | | 9 |
| | 7 |
| | 16 |
|
| Total noncurrent regulatory assets | | $ | 395 |
| | $ | 822 |
| | $ | 1,230 |
| | | $ | 619 |
| | $ | 816 |
| | $ | 1,437 |
|
| Current regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(b) | | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Over-recovered Illinois electric power costs(c) | | — |
| | 16 |
| | 16 |
| | | — |
| | 25 |
| | 25 |
|
Over-recovered PGA(c) | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
MTM derivative gains(d) | | 13 |
| | — |
| | 13 |
|
| | 12 |
| | 11 |
| | 23 |
|
Energy-efficiency riders(e) | | 2 |
| | 40 |
| | 42 |
| | | — |
| | — |
| | — |
|
Estimated refund for FERC complaint case(w) | | — |
| | 25 |
| | 42 |
| | | — |
| | 42 |
| | 62 |
|
| Other | | — |
| | 10 |
| | 10 |
| | | — |
| | — |
| | — |
|
| Total current regulatory liabilities | | $ | 19 |
| | $ | 92 |
| | $ | 128 |
| | | $ | 12 |
| | $ | 78 |
| | $ | 110 |
|
| Noncurrent regulatory liabilities: | | | | | | | | | | | | | |
Income taxes(j) | | $ | 1,392 |
| | $ | 842 |
| | $ | 2,323 |
| | | $ | 33 |
| | $ | 4 |
| | $ | 37 |
|
Uncertain tax positions tracker(k) | | 2 |
| | — |
| | 2 |
| | | 3 |
| | — |
| | 3 |
|
Asset removal costs(x) | | 995 |
| | 725 |
| | 1,725 |
| | | 970 |
| | 697 |
| | 1,669 |
|
ARO(l) | | 223 |
| | — |
| | 223 |
| | | 162 |
| | — |
| | 162 |
|
Bad debt rider(y) | | — |
| | 2 |
| | 2 |
| | | — |
| | 3 |
| | 3 |
|
Pension and postretirement benefit costs tracker(z) | | 35 |
| | — |
| | 35 |
| | | 35 |
| | — |
| | 35 |
|
Energy-efficiency riders(e) | | — |
| | — |
| | — |
| | | — |
| | 45 |
| | 45 |
|
Renewable energy credits and zero-emission credits(aa) | | — |
| | 58 |
| | 58 |
| | | — |
| | 15 |
| | 15 |
|
Storm tracker(ab) | | 6 |
| | — |
| | 6 |
| | | 7 |
| | — |
| | 7 |
|
| Other | | 11 |
| | 2 |
| | 13 |
| | | 5 |
| | 4 |
| | 9 |
|
| Total noncurrent regulatory liabilities | | $ | 2,664 |
| | $ | 1,629 |
| | $ | 4,387 |
| | | $ | 1,215 |
| | $ | 768 |
| | $ | 1,985 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2019 | | | 2018 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Regulatory assets: | | | | | | | | | | | | | |
Under-recovered Illinois electric power costs(a) | | $ | — |
| | $ | 4 |
| | $ | 4 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Under-recovered PGA(a) | | — |
| | — |
| | — |
| | | — |
| | 7 |
| | 7 |
|
MTM derivative losses(b) | | 12 |
|
| 242 |
| | 254 |
| | | 19 |
| | 197 |
| | 216 |
|
IEIMA revenue requirement reconciliation adjustment(c)(d) | | — |
| | 17 |
| | 17 |
| | | — |
| | 70 |
| | 70 |
|
FERC revenue requirement reconciliation adjustment(e) | | — |
| | 1 |
| | 16 |
| | | — |
| | 16 |
| | 30 |
|
Pension and postretirement benefit costs(f) | | 7 |
| | 26 |
| | 33 |
| | | 103 |
| | 149 |
| | 252 |
|
Income taxes(g) | | 114 |
| | 61 |
| | 177 |
| | | 119 |
| | 68 |
| | 185 |
|
Callaway costs(d)(h) | | 18 |
| | — |
| | 18 |
| | | 22 |
| | — |
| | 22 |
|
Unamortized loss on reacquired debt(i) | | 55 |
| | 31 |
| | 86 |
| | | 58 |
| | 40 |
| | 98 |
|
Environmental cost riders(j) | | — |
| | 127 |
| | 127 |
| | | — |
| | 148 |
| | 148 |
|
Storm costs(d)(k) | | — |
| | 7 |
| | 7 |
| | | — |
| | 13 |
| | 13 |
|
Workers’ compensation claims(l) | | 4 |
| | 7 |
| | 11 |
| | | 4 |
| | 7 |
| | 11 |
|
Construction accounting for pollution control equipment(d)(m) | | 15 |
| | — |
| | 15 |
| | | 16 |
| | — |
| | 16 |
|
Solar rebate program(n) | | 5 |
| | — |
| | 5 |
| | | 14 |
| | — |
| | 14 |
|
PISA(o)(d) | | 41 |
| | — |
| | 41 |
| | | 1 |
| | — |
| | 1 |
|
RESRAM(p) | | 9 |
| | — |
| | 9 |
| | | — |
| | — |
| | — |
|
FEJA energy-efficiency rider(d)(q) | | — |
| | 211 |
| | 211 |
| | | — |
| | 136 |
| | 136 |
|
| Other | | 13 |
| | 17 |
| | 30 |
| | | 24 |
| | 18 |
| | 42 |
|
| Total regulatory assets | | $ | 293 |
| | $ | 751 |
| | $ | 1,061 |
| | | $ | 380 |
| | $ | 869 |
| | $ | 1,261 |
|
| Less: current regulatory assets | | (8 | ) | | (57 | ) | | (69 | ) | | | (14 | ) | | (110 | ) | | (134 | ) |
| Noncurrent regulatory assets | | $ | 285 |
| | $ | 694 |
| | $ | 992 |
| | | $ | 366 |
| | $ | 759 |
| | $ | 1,127 |
|
| Regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(r) | | $ | 39 |
| | $ | — |
| | $ | 39 |
| | | $ | 34 |
| | $ | — |
| | $ | 34 |
|
Over-recovered Illinois electric power costs(a) | | — |
| | 11 |
| | 11 |
| | | — |
| | 12 |
| | 12 |
|
Over-recovered PGA(a) | | 8 |
| | 14 |
| | 22 |
| | | 7 |
| | 3 |
| | 10 |
|
Over-recovered VBA rider(s) | | — |
| | 8 |
| | 8 |
| | | — |
| | 8 |
| | 8 |
|
MTM derivative gains(b) | | 18 |
| | 3 |
| | 21 |
|
| | 5 |
| | 3 |
| | 8 |
|
IEIMA revenue requirement reconciliation adjustment(c) | | — |
| | 18 |
| | 18 |
| | | — |
| | — |
| | — |
|
FERC revenue requirement reconciliation adjustment(e) | | — |
| | 37 |
| | 38 |
| | | — |
| | 17 |
| | 19 |
|
MEEIA energy-efficiency rider(t) | | 3 |
| | — |
| | 3 |
| | | 19 |
| | — |
| | 19 |
|
Estimated refund for FERC complaint cases(u) | | — |
| | 23 |
| | 40 |
| | | — |
| | 26 |
| | 44 |
|
Income taxes(g) | | 1,428 |
| | 813 |
| | 2,326 |
| | | 1,484 |
| | 843 |
| | 2,413 |
|
Cost of removal(v) | | 1,041 |
| | 827 |
| | 1,884 |
| | | 1,027 |
| | 774 |
| | 1,811 |
|
AROs(w) | | 303 |
| | — |
| | 303 |
| | | 175 |
| | — |
| | 175 |
|
Pension and postretirement benefit costs tracker(x) | | 72 |
| | — |
| | 72 |
| | | 43 |
| | — |
| | 43 |
|
Renewable energy credits and zero emission credits(y) | | — |
| | 155 |
| | 155 |
| | | — |
| | 102 |
| | 102 |
|
Excess income taxes collected in 2018(z) | | 60 |
| | — |
| | 60 |
| | | 60 |
| | — |
| | 60 |
|
| Other | | 27 |
| | 24 |
| | 51 |
| | | 13 |
| | 15 |
| | 28 |
|
| Total regulatory liabilities | | $ | 2,999 |
| | $ | 1,933 |
| | $ | 5,051 |
| | | $ | 2,867 |
| | $ | 1,803 |
| | $ | 4,786 |
|
| Less: current regulatory liabilities | | (62 | ) | | (84 | ) | | (164 | ) | | | (68 | ) | | (62 | ) | | $ | (149 | ) |
| Noncurrent regulatory liabilities | | $ | 2,937 |
| | $ | 1,849 |
| | $ | 4,887 |
| | | $ | 2,799 |
| | $ | 1,741 |
| | $ | 4,637 |
|
| |
| (a) | These assets earn a return.Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. |
| |
| (b) | Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information. |
| |
| (c) | The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recovery or over-recovery will be recovered from, or refunded to, customers with interest within two years. |
| |
| (d) | These assets earn a return at the applicable WACC. |
| |
| (e) | Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years. |
| |
| (f) | These costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information. |
| |
| (g) | The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction and the effects of tax rate changes. The regulatory liabilities represent amounts that will be refunded to customers for deferred income taxes related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 34, 26, and 43 years. |
| |
| (h) | Ameren Missouri’s Callaway Energy Center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the original remaining life of the energy center. |
| |
| (i) | Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued. |
| |
| (j) | The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information. |
| |
| (k) | Storm costs from 2016 and 2018 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred. |
| |
| (l) | The period of recovery will depend on the timing of actual expenditures. |
| |
| (m) | The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux Energy Center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux Energy Center, currently through 2033. |
| |
| (n) | Costs associated with Ameren Missouri’s solar rebate program. The amortization period for these assets will be determined in a future electric service regulatory rate review. |
| |
| (o) | Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Accumulated PISA deferrals are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review. |
| |
| (p) | Costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Costs incurred over a twelve-month period beginning each August are amortized over a twelve-month period beginning February the following year. |
| |
| (q) | The electric energy-efficiency investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from 7 to 12 years. |
| |
| (r) | Under-recovered or over-recovered fuel costs to be recovered or refunded through the FAC. Specific accumulation periods aggregate the under-recovered or over-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from, or refund to, customers that occurs over the next eight months. |
| |
(c)(s) | Under-recovered or over-recovered costsnatural gas revenue caused by sales volume deviations from utility customers. Amountsweather normalized sales approved by the ICC in rate regulatory reviews. Each year’s amount will be recovered from or refunded to customers within one yearfrom April through December of the deferral.following year. |
| |
(d)(t) | Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information. |
| |
(e) | The Ameren Missouri balance relates to the MEEIA. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs, net shared benefits,lost electric margins, and the throughput disincentive.performance incentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, net shared benefits, and the throughput disincentivelost electric margins are incurred. The Ameren Illinois balance relates to a regulatory tracking mechanism to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer |
energy efficiency and demand response programs. Any under-recovery or over-recovery will be collected from or refunded to customers over the year following the plan year.
| |
(f) | The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recoveryincurred or over-recovery will be recovered from or refunded to customers with interest within two years.any performance incentive are earned. |
| |
(g)(u) | Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuantThe 2019 balances represent the estimated refunds to transmission customers related to the FERC’s electricNovember 2019 FERC order in the November 2013 FERC complaint case. The 2018 balances represent the estimated refunds to transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from or refundedcustomers related to customers within two years.the February 2015 FERC complaint case, which was dismissed in the November 2019 order. See further discussion of the FERC ROE complaint cases above. |
| |
(h)(v) | Under-recovered natural gas sales volumes, including deviationsEstimated funds collected from normal weather conditions. Each year’s amount will be recoveredcustomers to pay for the future removal cost of property, plant, and equipment retired from or refunded to, customers from April through Decemberservice, net of the following year.salvage. |
| |
(i) | These costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information. |
| |
(j) | The regulatory assets represent deferred income taxes that will be recovered from customers related to the equity component of allowance for funds used during construction and the effects of tax rate changes from the TCJA and the increased income tax rate in Illinois. The regulatory liabilities represent deferred income taxes that will be refunded to customers related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, depreciation differences, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. The amortization period for the effects of tax rate changes from the TCJA and the increased income tax rate in Illinois and the other tax liabilities will be determined in future rate orders by the applicable regulators. See Note 12 – Income Taxes for amounts related to the revaluation of deferred income taxes under the TCJA. |
| |
(k) | The tracker is amortized over three years, beginning from the date the amounts are included in rates. See Note 12 – Income Taxes for additional information. |
| |
(l)(w) | Recoverable or refundable removal costs for AROs, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations. |
| |
(m) | Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the energy center’s original operating license through 2024. |
| |
(n) | Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued. |
| |
(o) | The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information. |
| |
(p) | Storm costs from 2013, 2015, and 2016 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred. |
| |
(q) | Demand-side costs incurred prior to implementation of the MEEIA in 2013, including the costs of developing, implementing, and evaluating customer energy-efficiency and demand response programs. The MoPSC March 2017 electric rate order modified certain amortization periods for these costs. Costs incurred from May 2008 through September 2008, and from January 2010 through July 2012, are being amortized over a two-year period that began in April 2017. Costs incurred from October 2008 through December 2009 are no longer being amortized as of April 2017, and a new amortization period for these costs will be determined in a future regulatory rate review. Costs incurred from August 2012 through December 2012 are being amortized over a six-year period that began in June 2015. |
| |
(r) | The period of recovery will depend on the timing of actual expenditures. |
| |
(s) | Ameren Missouri’s costs incurred to enter into and maintain the Missouri Credit Agreement. These costs are being amortized over the life of the credit facility to construction work in progress, which will be depreciated when assets are placed in service. Additional costs were incurred in December 2016 to amend and restate the Missouri Credit Agreement. |
| |
(t) | The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux energy center, currently through 2033. |
| |
(u) | Costs associated with Ameren Missouri’s solar rebate program to fulfill its renewable energy portfolio requirement. Costs incurred from 2010 to 2014 are being amortized over a two-year period that began in April 2017 as modified per the MoPSC March 2017 electric rate order. Costs incurred from 2015 to 2016 are being amortized over a three-year period that began in April 2017. |
| |
(v) | Electric energy-efficiency program investments deferred under the FEJA. These investments will earn a return at Ameren Illinois’ weighted-average cost of capital with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The investments are being amortized over their weighted-average useful lives beginning in the period in which they were made. |
| |
(w) | Estimated refunds to transmission customers related to the February 2015 FERC Complaint Case discussed above. |
| |
| (x) | Estimated funds collected for the eventual dismantling and removal of plant retired from service, net of salvage value. |
| |
(y) | A regulatory tracking mechanism for the difference between the level of bad debt incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 2015 was refunded to customers from June 2016 through May 2017. The over-recovery relating to 2016 is being refunded to customers from June 2017 through May 2018. The over-recovery relating to 2017 will be refunded to customers from June 2018 through May 2019. |
| |
(z) | A regulatory trackingrecovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For costs incurred prior to August 2012, the amounts are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. For costs incurred between August 2012 and December 2014, the MoPSC’s May 2015 electric rate order directed the amortization period to occur over a five-year period that began in June 2015. For costs incurred between January 2012 and December 2016, the MoPSC’s March 2017 electric rate order directed theweighted-average remaining amortization period to occur over a five-year period that began in April 2017.is three years. For costs incurred after December 2016, the amortization period will be determined in a futurethe current electric service regulatory rate review. |
| |
(aa)(y) | Funds collected from customers and alternative retail electric suppliers for the purchase of renewable energy credits and zero-emissionzero emission credits through IPA procurements. The balance will be amortized as the credits are purchased. |
| |
(ab)(z) | AThe excess amount collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory tracking mechanism at Ameren Missouri for the difference between the level of storm costs incurredliability will be reflected in a particular year and the level of such costs included in rates. For periods prior to December 2014, the MoPSC’s April 2015 electric rate order directed the amortization to occurcustomer rates over a five-year period that beganof time to be determined by the MoPSC in June 2015. For periods after December 2014, the MoPSC’s March 2017current electric service regulatory rate order directed the amortization to occur over a five-year period that began in April 2017. The April 2015 MoPSC order did not approve the continued use of the storm cost regulatory tracking mechanism.review. |
Ameren, Ameren Missouri, and Ameren Illinois continually assess the recoverability of their regulatory assets. Regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts are credited to earnings.
NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET
The following table presents property, plant, and equipment, net, for each of the Ameren Companies at December 31, 20172019 and 20162018:
|
| | | | | | | | | | | | | | | | |
| | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) |
| 2019 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 11,880 |
| | $ | — |
| | $ | — |
| | $ | 11,880 |
|
| Electric distribution | | 6,371 |
| | 6,299 |
| | — |
| | 12,670 |
|
| Electric transmission | | 1,405 |
| | 3,101 |
| | 1,642 |
| | 6,148 |
|
| Natural gas | | 528 |
| | 3,024 |
| | — |
| | 3,552 |
|
Other(c) | | 1,173 |
| | 993 |
| | 236 |
| | 2,402 |
|
| | | 21,357 |
| | 13,417 |
| | 1,878 |
| | 36,652 |
|
| Less: Accumulated depreciation and amortization | | 9,195 |
| | 3,536 |
| | 275 |
| | 13,006 |
|
| | | 12,162 |
| | 9,881 |
| | 1,603 |
| | 23,646 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 135 |
| | — |
| | — |
| | 135 |
|
| Other | | 338 |
| | 202 |
| | 55 |
| | 595 |
|
| Property, plant, and equipment, net | | $ | 12,635 |
| | $ | 10,083 |
| | $ | 1,658 |
| | $ | 24,376 |
|
| 2018 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 11,432 |
| | $ | — |
| | $ | — |
| | $ | 11,432 |
|
| Electric distribution | | 5,989 |
| | 5,970 |
| | — |
| | 11,959 |
|
| Electric transmission | | 1,277 |
| | 2,647 |
| | 1,385 |
| | 5,309 |
|
| Natural gas | | 500 |
| | 2,701 |
| | — |
| | 3,201 |
|
Other(c) | | 1,008 |
| | 863 |
| | 230 |
| | 2,101 |
|
| | | 20,206 |
| | 12,181 |
| | 1,615 |
| | 34,002 |
|
| Less: Accumulated depreciation and amortization | | 8,726 |
| | 3,294 |
| | 253 |
| | 12,273 |
|
| | | 11,480 |
| | 8,887 |
| | 1,362 |
| | 21,729 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 217 |
| | — |
| | — |
| | 217 |
|
| Other | | 406 |
| | 311 |
| | 147 |
| | 864 |
|
| Property, plant, and equipment, net | | $ | 12,103 |
| | $ | 9,198 |
| | $ | 1,509 |
| | $ | 22,810 |
|
|
| | | | | | | | | | | | | | | | |
| | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) |
| 2017 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 11,132 |
| | $ | — |
| | $ | — |
| | $ | 11,132 |
|
| Electric distribution | | 5,766 |
| | 5,649 |
| | — |
| | 11,415 |
|
| Electric transmission | | 1,201 |
| | 2,298 |
| | 1,167 |
| | 4,666 |
|
| Natural gas | | 474 |
| | 2,419 |
| | — |
| | 2,893 |
|
Other(c) | | 922 |
| | 757 |
| | 242 |
| | 1,921 |
|
| | | 19,495 |
| | 11,123 |
| | 1,409 |
| | 32,027 |
|
| Less: Accumulated depreciation and amortization | | 8,305 |
| | 3,082 |
| | 246 |
| | 11,633 |
|
| | | 11,190 |
| | 8,041 |
| | 1,163 |
| | 20,394 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 148 |
| | — |
| | — |
| | 148 |
|
| Other | | 413 |
| | 252 |
| | 259 |
| | 924 |
|
| Property, plant, and equipment, net | | $ | 11,751 |
| | $ | 8,293 |
| | $ | 1,422 |
| | $ | 21,466 |
|
| 2016 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 10,911 |
| | $ | — |
| | $ | — |
| | $ | 10,911 |
|
| Electric distribution | | 5,563 |
| | 5,287 |
| | — |
| | 10,850 |
|
| Electric transmission | | 1,151 |
| | 2,016 |
| | 712 |
| | 3,879 |
|
| Natural gas | | 455 |
| | 2,186 |
| | — |
| | 2,641 |
|
Other(c) | | 879 |
| | 719 |
| | 239 |
| | 1,837 |
|
| | | 18,959 |
| | 10,208 |
| | 951 |
| | 30,118 |
|
| Less: Accumulated depreciation and amortization | | 7,880 |
| | 2,850 |
| | 231 |
| | 10,961 |
|
| | | 11,079 |
| | 7,358 |
| | 720 |
| | 19,157 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 206 |
| | — |
| | — |
| | 206 |
|
| Other | | 193 |
| | 111 |
| | 446 |
| | 750 |
|
| Property, plant, and equipment, net | | $ | 11,478 |
| | $ | 7,469 |
| | $ | 1,166 |
| | $ | 20,113 |
|
| |
| (a) | Amounts in Ameren and Ameren Missouri include two2 CTs under separate capital lease agreements.that have related financing obligations. The gross cumulative asset value of those agreements was $233$236 million and $232$235 million at December 31, 20172019 and 2016,2018, respectively. The total accumulated depreciation associated with the two2 CTs was $83$95 million and $77$89 million at December 31, 20172019 and 2016,2018, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these capital lease agreements. |
| |
| (b) | The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydro generating assets which have useful lives of up to 150 years, 20 to 80 years for electric distribution, 50 to 75 years for electric transmission, 20 to 80 years for natural gas, and 5 to 55 years for other. |
| |
| (c) | Other property, plant, and equipment includes assets used to support electric and natural gas services. |
Capitalized software costs are classified within “Property, Plant, and Equipment, Net” on the balance sheet and are amortized on a straight-line basis over the expected period of benefit, ranging from 5 to 10 years. The following table presents the amortization, gross carrying value, of capitalized software, theand related accumulated amortization and the amortization expense of capitalized software by year:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Amortization Expense | | Gross Carrying Value | | Accumulated Amortization |
| | | 2019 | 2018 | 2017 | | 2019 | 2018 | | 2019 | 2018 |
| Ameren | | $ | 78 |
| $ | 71 |
| $ | 58 |
| | $ | 901 |
| $ | 734 |
| | $ | (584 | ) | $ | (514 | ) |
| Ameren Missouri | | 30 |
| 24 |
| 20 |
| | 303 |
| 223 |
| | (153 | ) | (125 | ) |
| Ameren Illinois | | 45 |
| 44 |
| 36 |
| | 377 |
| 297 |
| | (221 | ) | (183 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Amortization Expense(a) | | Gross Carrying Value | | Accumulated Amortization |
| | | 2017 | 2016 | 2015 | | 2017 | 2016 | | 2017 | 2016 |
| Ameren | | $ | 58 |
| $ | 52 |
| $ | 47 |
| | $ | 655 |
| $ | 622 |
| | $ | (466 | ) | $ | (408 | ) |
| Ameren Missouri | | 20 |
| 17 |
| 16 |
| | 191 |
| 178 |
| | (107 | ) | (87 | ) |
| Ameren Illinois | | 36 |
| 33 |
| 27 |
| | 241 |
| 225 |
| | (146 | ) | (110 | ) |
| |
(a) | AsAnnual amortization expense for capitalized costs for software placed in service as of December 31, 2017, the estimated amortization expense of capitalized software for each of the five succeeding years is not expected to differ materially from the current year expense. |
The following table provides accrued capital and nuclear fuel expenditures at December 31, 2017, 2016, and 2015, which represent noncash investing activity excluded from the accompanying statements of cash flows:2019, is estimated to be as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| Ameren | | $ | 80 |
| | $ | 74 |
| | $ | 63 |
| | $ | 50 |
| | $ | 24 |
|
| Ameren Missouri | | 36 |
| | 34 |
| | 29 |
| | 24 |
| | 12 |
|
| Ameren Illinois | | 41 |
| | 36 |
| | 32 |
| | 24 |
| | 12 |
|
|
| | | | | | | | | | | |
| | Ameren(a) | | Ameren Missouri | | Ameren Illinois |
| Accrued capital expenditures: | | | | | |
| 2017 | $ | 361 |
| | $ | 159 |
| | $ | 175 |
|
| 2016 | 251 |
| | 116 |
| | 87 |
|
| 2015 | 235 |
| | 85 |
| | 92 |
|
| Accrued nuclear fuel expenditures: | | | | | |
| 2017 | 10 |
| | 10 |
| | (b) |
|
| 2016 | 20 |
| | 20 |
| | (b) |
|
| 2015 | 16 |
| | 16 |
| | (b) |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
NOTE 4 – SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings.
Credit Agreements
In December 2019, the Credit Agreements were amended and restated. The amended and restated agreements, among other things, extended the maturity dates of the Credit Agreements and provide $2.3 billion of credit through the extended maturity date. The total facility size of the Missouri Credit Agreement was increased from $1.0 billion to $1.2 billion. The total facility size of the Illinois Credit Agreement remained unchanged at $1.1 billion. The Credit Agreements, provide $2.1 billion of credit cumulatively through maturitywhich were previously scheduled to mature in December 2021.2022, are now scheduled to mature in December 2024. The maturity date may be extended for two additional one-year periods upon mutual consent of the borrowers and lenders. Credit available under the agreements is provided by a group of 22 international, national, and regional lenders, with no single lender providing more than $118$130 million of credit in aggregate.
The obligations of each borrower under the respective Credit Agreements to which it is a party are several and not joint. Except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective Credit Agreements are not guaranteed by Ameren (parent) or any other subsidiary of Ameren. The following table presents the maximum aggregate amount available to each borrower under each facility:
| | | | | Missouri Credit Agreement | Illinois Credit Agreement | | Missouri Credit Agreement | Illinois Credit Agreement |
| Ameren (parent) | | $ | 700 |
| $ | 500 |
| | $ | 900 |
| $ | 500 |
|
| Ameren Missouri | | 800 |
| (a) |
| | 850 |
| (a) |
|
| Ameren Illinois | | (a) |
| 800 |
| | (a) |
| 800 |
|
The borrowers have the option to seek additional commitments from existing or new lenders to increase the total facility size of the Credit Agreements to a maximum of $1.2$1.4 billion for the Missouri Credit Agreement and $1.3 billion for the Illinois Credit Agreement. Ameren (parent) borrowings are due and payable no later than the maturity date of the Credit Agreements. Ameren Missouri and Ameren Illinois borrowings under the applicable Credit Agreement are due and payable no later than the earlier of the maturity date or 364 days after the originating date of the borrowing.
The obligations of the borrowers under the Credit Agreements are unsecured. Loans are available on a revolving basis under each of the Credit Agreements. Funds borrowed may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate plus the margin applicable to the particular borrower and/or the eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower’s long-term unsecured credit ratings or, if no such ratings are in effect, the borrower’s corporate/issuer ratings then in effect. The borrowers have received commitments from the lenders to issue letters of credit up to $100 million under each of the Credit Agreements. In addition, the issuance of letters of credit is subject to the $2.1$2.3 billion overall combined facility borrowing limitations of the Credit Agreements.
The borrowers will use the proceeds from any borrowings under the Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, issuance of letters of credit, loan funding under the Ameren money pool arrangements, and other short-term affiliate loan arrangements. The Missouri Credit Agreement and the Illinois Credit Agreement are available to support issuances under Ameren (parent)’s, Ameren Missouri’s and Ameren Illinois’ commercial paper programs, respectively, subject to borrowing
sublimits. As of December 31, 2017,2019, based on commercial paper outstanding and letters of credit issued under the Credit Agreements, along with cash and cash equivalents, the aggregate amount of credit capacitynet liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $1.6$1.9 billion.
Ameren, Ameren Missouri, and Ameren Illinois did not borrow under the Credit Agreements for the years ended December 31, 20172019 and 2016.2018.
Commercial Paper
The following table summarizes the borrowing activity and relevant interest rates under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the years ended December 31, 20172019 and 20162018:
|
| | | | | | | | | | | | | | | | | |
| | | Ameren (parent) | | Ameren Missouri | | Ameren Illinois | | Ameren Consolidated | |
| 2019 | | | | | | | | | |
| Average daily commercial paper outstanding | | $ | 421 |
| | $ | 122 |
| | $ | 157 |
| | $ | 700 |
| |
| Outstanding borrowings at period-end | | 153 |
| | 234 |
| | 53 |
| | 440 |
| |
| Weighted-average interest rate | | 2.66 | % | | 2.62 | % | | 2.43 | % | | 2.60 | % | |
Peak outstanding commercial paper during period(a) | | $ | 651 |
| | $ | 549 |
| | $ | 356 |
| | $ | 1,113 |
| |
| Peak interest rate | | 3.80 | % | (b) | 2.97 | % | | 5.00 | % | (b) | 5.00 | % | (b) |
| 2018 | | | | | | | | | |
| Average daily commercial paper outstanding | | $ | 410 |
| | $ | 61 |
| | $ | 108 |
| | $ | 579 |
| |
| Outstanding borrowings at period-end | | 470 |
| | 55 |
| | 72 |
| | 597 |
| |
| Weighted-average interest rate | | 2.31 | % | | 1.94 | % | | 2.26 | % | | 2.26 | % | |
Peak outstanding commercial paper during period(a) | | $ | 543 |
| | $ | 481 |
| | $ | 442 |
| | $ | 1,295 |
| |
| Peak interest rate | | 3.10 | % | | 2.80 | % | | 2.85 | % | | 3.10 | % | |
|
| | | | | | | | | | | | | | |
| | | Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated |
| 2017 | | | | | | |
| Average daily commercial paper outstanding | | $ | 573 |
| | $ | 5 |
| $ | 90 |
| $ | 668 |
|
| Outstanding borrowings at period-end | | 383 |
| | 39 |
| 62 |
| 484 |
|
| Weighted-average interest rate | | 1.30 | % | | 1.24 | % | 1.35 | % | 1.31 | % |
Peak outstanding commercial paper during period(a) | | $ | 841 |
| | $ | 64 |
| $ | 469 |
| $ | 948 |
|
| Peak interest rate | | 1.90 | % | | 1.78 | % | 2.00 | % | 2.00 | % |
| 2016 | | | | | | |
| Average daily commercial paper outstanding | | $ | 440 |
| | $ | 60 |
| $ | 52 |
| $ | 552 |
|
| Outstanding borrowings at period-end | | 507 |
| | — |
| 51 |
| 558 |
|
| Weighted-average interest rate | | 0.82 | % | | 0.74 | % | 0.69 | % | 0.80 | % |
Peak outstanding commercial paper during period(a) | | $ | 574 |
| | $ | 208 |
| $ | 195 |
| $ | 839 |
|
| Peak interest rate | | 1.05 | % | | 0.85 | % | 0.90 | % | 1.05 | % |
| |
| (a) | The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of the peak amounts presented by the companies may not equal the Ameren consolidated peak amount for the period. |
| |
| (b) | In 2019, the peak interest rate was affected by temporary disruptions in the commercial paper market. |
Indebtedness Provisions and Other Covenants
The information below is a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants.
The Credit Agreements contain conditions for borrowings and issuances of letters of credit. These conditions include the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation, and the absence of any notice of violation, liability, or requirement under any environmental laws that could have a material adverse effect), and obtaining required regulatory authorizations. In addition, it is a condition for any Ameren Illinois borrowing that, at the time of and after giving effect to such borrowing, Ameren Illinois not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation.
The Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur certain liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The Credit Agreements require each of Ameren, Ameren Missouri, and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of December 31, 2017,2019, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 53%54%, 48%49%, and 47%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
The Credit Agreements contain default provisions that apply separately to each borrower. However, a default of Ameren Missouri or Ameren Illinois under the applicable credit agreement is also deemed to constitute a default of Ameren (parent) under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $100 million in the aggregate (including under the other credit agreement). However, under the default provisions of the Credit Agreements, any default of Ameren (parent) under either credit agreement that results solely from a default of Ameren Missouri or Ameren Illinois does not result in a cross-default of Ameren (parent) under the other credit agreement. Further, the Credit Agreements default provisions provide that an Ameren (parent) default under either of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.
None of the Ameren Companies’ credit agreementsCredit Agreements or financing agreements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. The Ameren Companies were in compliance with the provisions and covenants of their credit agreementsthe Credit Agreements at December 31, 20172019.
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.
Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the money pool from participants. The primary sources of external funds for the utility money pool are the Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but it is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations.
Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2017,2019, was 1.19% (20162.48% (2018 – 0.52%2.10%).
See Note 13 – Related-party Transactions for the amount of interest income and expense from the utility money pool arrangementsagreement recorded by the Ameren CompaniesMissouri and Ameren Illinois for the years ended December 31, 2017, 2016,2019, 2018, and 2015.2017.
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding, including maturities due within one year, for the Ameren Companies as of December 31, 20172019 and 20162018:
| | | | 2017 | | 2016 | 2019 | | 2018 |
| Ameren (Parent): | | | | | | |
| 2.70% Senior unsecured notes due 2020 | $ | 350 |
| | $ | 350 |
| $ | 350 |
| | $ | 350 |
|
| 2.50% Senior unsecured notes due 2024 | | 450 |
| | — |
|
| 3.65% Senior unsecured notes due 2026 | 350 |
| | 350 |
| 350 |
| | 350 |
|
| Total long-term debt, gross | 700 |
| | 700 |
| 1,150 |
| | 700 |
|
| Less: Unamortized debt issuance costs | (4 | ) | | (6 | ) | (6 | ) | | (3 | ) |
| Less: Maturities due within one year | | (350 | ) | | — |
|
| Long-term debt, net | $ | 696 |
| | $ | 694 |
| $ | 794 |
| | $ | 697 |
|
| Ameren Missouri: | | | | | | |
| Bonds and notes: | | | | | | |
6.40% Senior secured notes due 2017(a) | $ | — |
| | $ | 425 |
| |
6.00% Senior secured notes due 2018(a)(b) | 179 |
| | 179 |
| |
5.10% Senior secured notes due 2018(a) | 199 |
| | 199 |
| |
6.70% Senior secured notes due 2019(a)(b) | 329 |
| | 329 |
| |
5.10% Senior secured notes due 2019(a) | 244 |
| | 244 |
| |
| 6.70% Senior secured notes due 2019 | | $ | — |
| | $ | 329 |
|
| 5.10% Senior secured notes due 2019 | | — |
| | 244 |
|
5.00% Senior secured notes due 2020(a) | 85 |
| | 85 |
| 85 |
| | 85 |
|
1992 Series bonds due 2022(c)(d) | 47 |
| | 47 |
| |
1.60% 1992 Series bonds due 2022(b)(c) | | 47 |
| | 47 |
|
3.50% Senior secured notes due 2024(a) | 350 |
| | 350 |
| 350 |
| | 350 |
|
2.95% Senior secured notes due 2027(a) | 400 |
| | — |
| 400 |
| | 400 |
|
5.45% First mortgage bonds due 2028(e) | (e) |
| | (e) |
| |
1998 Series A bonds due 2033(c)(d) | 60 |
| | 60 |
| |
1998 Series B bonds due 2033(c)(d) | 50 |
| | 50 |
| |
1998 Series C bonds due 2033(c)(d) | 50 |
| | 50 |
| |
| 5.45% First mortgage bonds due 2028 | | — |
| | (d) |
|
3.50% First mortgage bonds due 2029(f) | | 450 |
| | — |
|
2.90% 1998 Series A bonds due 2033(b)(c) | | 60 |
| | 60 |
|
2.90% 1998 Series B bonds due 2033(b)(c) | | 50 |
| | 50 |
|
2.75% 1998 Series C bonds due 2033(b)(c) | | 50 |
| | 50 |
|
5.50% Senior secured notes due 2034(a) | 184 |
| | 184 |
| 184 |
| | 184 |
|
5.30% Senior secured notes due 2037(a) | 300 |
| | 300 |
| 300 |
| | 300 |
|
8.45% Senior secured notes due 2039(b)(e) | 350 |
| | 350 |
| 350 |
| | 350 |
|
3.90% Senior secured notes due 2042(b)(e) | 485 |
| | 485 |
| 485 |
| | 485 |
|
3.65% Senior secured notes due 2045(a) | 400 |
| | 400 |
| 400 |
| | 400 |
|
| Capital lease obligations: | | | | |
City of Bowling Green capital lease (Peno Creek CT) due 2022(f) | 36 |
| | 42 |
| |
Audrain County capital lease (Audrain County CT) due 2023(f) | 240 |
| | 240 |
| |
4.00% First mortgage bonds due 2048(f) | | 425 |
| | 425 |
|
3.25% First mortgage bonds due 2049(f) | | 330 |
| | — |
|
| Finance obligations: | | | | |
City of Bowling Green agreement (Peno Creek CT) due 2022(g) | | 23 |
| | 30 |
|
Audrain County agreement (Audrain County CT) due 2023(g) | | 240 |
| | 240 |
|
| Total long-term debt, gross | 3,988 |
| | 4,019 |
| 4,229 |
| | 4,029 |
|
| Less: Unamortized discount and premium | (7 | ) | | (6 | ) | (9 | ) | | (9 | ) |
| Less: Unamortized debt issuance costs | (20 | ) | | (19 | ) | (30 | ) | | (22 | ) |
| Less: Maturities due within one year | (384 | ) | | (431 | ) | (92 | ) | | (580 | ) |
| Long-term debt, net | $ | 3,577 |
| | $ | 3,563 |
| $ | 4,098 |
| | $ | 3,418 |
|
|
| | | | | | | |
| | 2019 | | 2018 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
2.70% Senior secured notes due 2022(h)(i) | $ | 400 |
| | $ | 400 |
|
| 5.90% First mortgage bonds due 2023 | — |
| | (d) |
|
| 5.70% First mortgage bonds due 2024 | — |
| | (d) |
|
3.25% Senior secured notes due 2025(h) | 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(h) | 60 |
| | 60 |
|
1993 Series B-1 Senior unsecured notes due 2028(c) | — |
| | 17 |
|
3.80% First mortgage bonds due 2028(j) | 430 |
| | 430 |
|
6.70% Senior secured notes due 2036(h) | 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(h) | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(h) | 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(h) | 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(h) | 490 |
| | 490 |
|
3.70% First mortgage bonds due 2047(j) | 500 |
| | 500 |
|
4.50% First mortgage bonds due 2049(j) | 500 |
| | 500 |
|
3.25% First mortgage bonds due 2050(j) | 300 |
| | — |
|
| Total long-term debt, gross | 3,613 |
| | 3,330 |
|
| Less: Unamortized discount and premium | (4 | ) | | (3 | ) |
| Less: Unamortized debt issuance costs | (34 | ) | | (31 | ) |
| Long-term debt, net | $ | 3,575 |
| | $ | 3,296 |
|
| ATXI: | | | |
3.43% Senior notes due 2050(k) | $ | 450 |
| | $ | 450 |
|
| Total long-term debt, gross | 450 |
| | 450 |
|
| Less: Unamortized debt issuance costs | (2 | ) | | (2 | ) |
| Long-term debt, net | $ | 448 |
| | $ | 448 |
|
| Ameren consolidated long-term debt, net | $ | 8,915 |
| | $ | 7,859 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
6.125% Senior secured notes due 2017(g)(h) | $ | — |
| | $ | 250 |
|
6.25% Senior secured notes due 2018(g)(h) | 144 |
| | 144 |
|
9.75% Senior secured notes due 2018(g)(h) | 313 |
| | 313 |
|
2.70% Senior secured notes due 2022(g)(h) | 400 |
| | 400 |
|
5.90% First mortgage bonds due 2023(i) | (i) |
| | (i) |
|
5.70% First mortgage bonds due 2024(j) | (j) |
| | (j) |
|
3.25% Senior secured notes due 2025(g) | 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(g) | 60 |
| | 60 |
|
1993 Series B-1 Senior unsecured notes due 2028(d)(k) | 17 |
| | 17 |
|
6.70% Senior secured notes due 2036(g) | 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(l) | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(g) | 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(g) | 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(g) | 490 |
| | 490 |
|
3.70% First mortgage bonds due 2047(m) | 500 |
| | — |
|
| Total long-term debt, gross | 2,857 |
| | 2,607 |
|
| Less: Unamortized discount and premium | (3 | ) | | — |
|
| Less: Unamortized debt issuance costs | (24 | ) | | (19 | ) |
| Less: Maturities due within one year | (457 | ) | | (250 | ) |
| Long-term debt, net | $ | 2,373 |
| | $ | 2,338 |
|
| ATXI: | | | |
3.43% Senior notes due 2050(n) | $ | 450 |
| | $ | — |
|
| Total long-term debt, gross | 450 |
| | — |
|
| Less: Unamortized debt issuance costs | (2 | ) | | — |
|
| Long-term debt, net | $ | 448 |
| | $ | — |
|
| Ameren consolidated long-term debt, net | $ | 7,094 |
| | $ | 6,595 |
|
| |
| (a) | These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the Ameren Missouri2049 maturity of the 3.25% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes currently outstanding, we dodescribed in footnote (e) below, Ameren Missouri does not expect the first mortgage bond lien protection associated with these notes to fall away before 2042.away. |
| |
| (b) | These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes. |
| |
| (c) | Prior to the change in the method of determining the interest rates applicable to the Ameren Missouri bonds and the extinguishment of Ameren Illinois’ senior unsecured notes, the interest rates and the periods during which such rates apply varied depending on our selection of defined rate modes. The average interest rates for the respective applicable period in 2019 and the year ended December 31, 2018 were as follows: |
|
| | | |
| | 2019 | | 2018 |
| Ameren Missouri 1992 Series due 2022 | 2.58% | | 2.37% |
| Ameren Missouri 1998 Series A due 2033 | 3.43% | | 2.76% |
| Ameren Missouri 1998 Series B due 2033 | 3.57% | | 2.79% |
| Ameren Missouri 1998 Series C due 2033 | 3.43% | | 2.83% |
| Ameren Illinois 1993 Series B-1 due 2028 | 1.68% | | 1.58% |
| |
| (d) | Amount less than $1 million. |
| |
| (e) | Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 6.00% senior secured notes due 2018, 6.70% senior secured notes due 2019, and 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions. |
| |
(c)(f) | These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes. The bonds are also backed by an insurance guarantee policy. |
| |
(d) | The interest rates and the periods during which such rates apply vary depending on our selection of defined rate modes. Maximum interest rates could reach 18%, depending on the series of bonds. The bonds are callable at 100% of par value. The average interest rates for 2017 and 2016 were as follows:
|
|
| | | |
| | 2017 | | 2016 |
| Ameren Missouri 1992 Series due 2022 | 1.43% | | 0.66% |
| Ameren Missouri 1998 Series A due 2033 | 1.77% | | 0.91% |
| Ameren Missouri 1998 Series B due 2033 | 1.75% | | 0.92% |
| Ameren Missouri 1998 Series C due 2033 | 1.73% | | 0.97% |
| Ameren Illinois 1993 Series B-1 due 2028 | 1.08% | | 0.70% |
| |
(e) | These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture andindenture. They are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value. Less than $1 million principal amount of the bonds remain outstanding. |
| |
(f)(g) | Payments due related to the lessor under these capital leasefinancing obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the lessorcity/county and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the capital lease agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the capital leasefinancing obligations and the related investments in debt securities, recorded in "Other“Other Assets,"” was $276$263 million and $282$270 million, respectively, as of December 31, 20172019 and 2016.2018. |
| |
(g)(h) | These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all Ameren Illinois property of the former IP and CIPS.franchises. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under its 1992 mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2050 maturity date of these senior secured notes and the 3.70%3.25% first mortgage bonds, due 2047, we doAmeren Illinois does not expect the first mortgage bond lien protection associated with these notes to fall away. |
| |
(h)(i) | Ameren Illinois has agreed that so long as any of the 2.70% senior secured notes due 2022 are outstanding, Ameren Illinois will not permit a release date to occur, and so long as any of the 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018 are outstanding, Ameren Illinois will not optionally redeem, purchase or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions; therefore, a release date will not occur so long as any of these notesoccur. |
remain outstanding.
| |
(i) | These bonds are first mortgage bonds issued by Ameren Illinois under its 1933 mortgage indenture. They are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value. Less than $1 million principal amount of the bonds remain outstanding. |
| |
| (j) | These bonds are first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all Ameren Illinois property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy. Less than $1 million principal amount of the bonds remains outstanding.franchises. |
| |
| (k) | The bonds are callable at 100% of par value. |
| |
(l) | These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its 1933 mortgage indenture. They are secured by substantially all property of the former CILCO. The notes have a fall-away lien provision, and Ameren Illinois could cause these notes to become unsecured at any time by redeeming the 5.90% first mortgage bonds due 2023 (of which less than $1 million principal amount remains outstanding). |
| |
(m) | These bonds are first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS. |
| |
(n) | The following table presents the principal maturities schedule for the 3.43% senior notes due 2050: |
|
| | |
| Payment Date | | Principal Payment |
| August 2022 | $ | 49.5 |
| August 2024 | | 49.5 |
| August 2027 | | 49.5 |
| August 2030 | | 49.5 |
| August 2032 | | 49.5 |
| August 2038 | | 49.5 |
| August 2043 | | 76.5 |
| August 2050 | | 76.5 |
| Total | $ | 450.0 |
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 20172019:
| | | | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated(a) |
| 2018 | $ | — |
| | $ | 384 |
| | $ | 457 |
| | $ | — |
| | $ | 841 |
| |
| 2019 | — |
| | 581 |
| | — |
| | — |
| | 581 |
| |
| 2020 | 350 |
| | 92 |
| | — |
| | — |
| | 442 |
| $ | 350 |
| | $ | 92 |
| | $ | — |
| | $ | — |
| | $ | 442 |
|
| 2021 | — |
| | 8 |
| | — |
| | — |
| | 8 |
| — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| 2022 | — |
| | 56 |
| | 400 |
| | 50 |
| | 506 |
| — |
| | 55 |
| | 400 |
| | 50 |
| | 505 |
|
| 2023 | | — |
| | 240 |
| | ��� |
| | — |
| | 240 |
|
| 2024 | | 450 |
| | 350 |
| | — |
| | 50 |
| | 850 |
|
| Thereafter | 350 |
| | 2,867 |
| | 2,000 |
| | 400 |
| | 5,617 |
| 350 |
| | 3,484 |
| | 3,213 |
| | 350 |
| | 7,397 |
|
| Total | $ | 700 |
| | $ | 3,988 |
| | $ | 2,857 |
| | $ | 450 |
| | $ | 7,995 |
| $ | 1,150 |
| | $ | 4,229 |
| | $ | 3,613 |
| | $ | 450 |
| | $ | 9,442 |
|
| |
| (a) | Excludes unamortized discount, unamortized premium, and debt issuance costs of $4$6 million, $2739 million, $27$38 million and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois and ATXI, respectively. |
All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends, have voting rights, and are not subject to mandatory redemption. The preferred stock of Ameren’s subsidiaries is included in “Noncontrolling Interests” on Ameren’s consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois, which is redeemable at the option of the issuer, at the prices shown below as of December 31, 20172019 and 20162018:
| | | | | Redemption Price (per share) | | 2017 | | 2016 | Shares Outstanding | | Redemption Price (per share) | | 2019 | | 2018 |
| Ameren Missouri: | | | | | | | | | | | | |
| Without par value and stated value of $100 per share, 25 million shares authorized | Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | | Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | |
| $3.50 Series | 130,000 shares | | $ | 110.00 |
| | $ | 13 |
| | $ | 13 |
| 130,000 shares | | $ | 110.00 |
| | $ | 13 |
| | $ | 13 |
|
| $3.70 Series | 40,000 shares | | 104.75 |
| | 4 |
| | 4 |
| 40,000 shares | | 104.75 |
| | 4 |
| | 4 |
|
| $4.00 Series | 150,000 shares | | 105.625 |
| | 15 |
| | 15 |
| 150,000 shares | | 105.625 |
| | 15 |
| | 15 |
|
| $4.30 Series | 40,000 shares | | 105.00 |
| | 4 |
| | 4 |
| 40,000 shares | | 105.00 |
| | 4 |
| | 4 |
|
| $4.50 Series | 213,595 shares | | 110.00 |
| (a) | 21 |
| | 21 |
| 213,595 shares | | 110.00 |
| (a) | 21 |
| | 21 |
|
| $4.56 Series | 200,000 shares | | 102.47 |
| | 20 |
| | 20 |
| 200,000 shares | | 102.47 |
| | 20 |
| | 20 |
|
| $4.75 Series | 20,000 shares | | 102.176 |
| | 2 |
| | 2 |
| 20,000 shares | | 102.176 |
| | 2 |
| | 2 |
|
| $5.50 Series A | 14,000 shares | | 110.00 |
| | 1 |
| | 1 |
| 14,000 shares | | 110.00 |
| | 1 |
| | 1 |
|
| Total | Total | | | | $ | 80 |
| | $ | 80 |
| Total | | | | $ | 80 |
| | $ | 80 |
|
| Ameren Illinois: | | | | | | | | | | | | |
| With par value of $100 per share, 2 million shares authorized | With par value of $100 per share, 2 million shares authorized | | | | | | | With par value of $100 per share, 2 million shares authorized | | | | | | |
| 4.00% Series | 144,275 shares | | $ | 101.00 |
| | $ | 14 |
| | $ | 14 |
| 144,275 shares | | $ | 101.00 |
| | $ | 14 |
| | $ | 14 |
|
| 4.08% Series | 45,224 shares | | 103.00 |
| | 5 |
| | 5 |
| 45,224 shares | | 103.00 |
| | 5 |
| | 5 |
|
| 4.20% Series | 23,655 shares | | 104.00 |
| | 2 |
| | 2 |
| 23,655 shares | | 104.00 |
| | 2 |
| | 2 |
|
| 4.25% Series | 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
| 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
|
| 4.26% Series | 16,621 shares | | 103.00 |
| | 2 |
| | 2 |
| 16,621 shares | | 103.00 |
| | 2 |
| | 2 |
|
| 4.42% Series | 16,190 shares | | 103.00 |
| | 2 |
| | 2 |
| 16,190 shares | | 103.00 |
| | 2 |
| | 2 |
|
| 4.70% Series | 18,429 shares | | 103.00 |
| | 2 |
| | 2 |
| 18,429 shares | | 103.00 |
| | 2 |
| | 2 |
|
| 4.90% Series | 73,825 shares | | 102.00 |
| | 7 |
| | 7 |
| 73,825 shares | | 102.00 |
| | 7 |
| | 7 |
|
| 4.92% Series | 49,289 shares | | 103.50 |
| | 5 |
| | 5 |
| 49,289 shares | | 103.50 |
| | 5 |
| | 5 |
|
| 5.16% Series | 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
| 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
|
| 6.625% Series | 124,274 shares | | 100.00 |
| | 12 |
| | 12 |
| 124,274 shares | | 100.00 |
| | 12 |
| | 12 |
|
| 7.75% Series | 4,542 shares | | 100.00 |
| | 1 |
| | 1 |
| 4,542 shares | | 100.00 |
| | 1 |
| | 1 |
|
| Total | Total | | | | $ | 62 |
| | $ | 62 |
| Total | | | | $ | 62 |
| | $ | 62 |
|
| Total Ameren | Total Ameren | | | | $ | 142 |
| | $ | 142 |
| Total Ameren | | | | $ | 142 |
| | $ | 142 |
|
| |
| (a) | In the event of voluntary liquidation, $105.50. |
Ameren has 100 million shares of $0.01$0.01 par value preferred stock authorized, with no0 such shares outstanding. Ameren Missouri has 7.5 million shares of $1$1 par value preference stock authorized, with no0 such shares outstanding. Ameren Illinois has 2.6 million shares of no0 par value preferred stock authorized, with no0 such shares outstanding.
Ameren
Under the DRPlus and its 401(k) plan, Ameren issued 0.9 million and 1.2 million shares of common stock in 2019 and 2018, respectively, and received proceeds of $68 million and $74 million for the respective years. In addition, Ameren issued 0.8 million and 0.7 million shares of common stock valued at $54 million and $35 million in 2019 and 2018, respectively, for no cash consideration in connection with stock-based compensation. Ameren did not issue any common stock in 2017.
In October 2018, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 4 million additional shares of its common stock under its 401(k) plan. Shares of common stock issuable under the 401(k) plan are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions.
In May 2017, Ameren filed a Form S-3 registration statement with the SEC, authorizing the offering of 6 million additional shares of its common stock under the DRPlus, which expires in May 2020. Shares of common stock sold under the DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions..
In December 2017, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuance of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing and expires in December 2020.
In August 2019, Ameren filedentered into a Form S-3 registration statementforward sale agreement with the SEC in May 2017, authorizing the offering of 6a counterparty relating to 7.5 million additional shares of its common stock under DRPlus, which expires in 2020. Sharesstock.The forward sale agreement can be settled at Ameren’s discretion on or prior to March 31, 2021. On a settlement date or dates, if Ameren elects to physically settle the forward sale agreement, Ameren will issue shares of common stock sold under DRPlus are,to the counterparty at Ameren’s option, newly issued shares, treasury shares, or shares purchasedthe then-applicable forward sale price. The forward sale price was initially $74.18 per share. The initial forward price is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the open marketforward sale agreement by specified amounts related to expected dividends on shares of the common stock during the term of the forward sale agreement. If the overnight bank funding rate is less than the spread on any day, the interest rate factor will result in a reduction of the forward sale price.
The forward sale agreement will be physically settled unless Ameren elects to settle in cash or in privately negotiated transactions. As ofto net share settle. At December 31, 2017 and 2016, DRPlus participant funds2019, Ameren could have settled the forward sale agreement with physical delivery of $87.5 million were reflected on Ameren’s consolidated balance sheets in “Other current assets.”
In 2013, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 4 million additional shares of its common stock under its 401(k) plan. Shares of common stock sold underto the 401(k) plan are,counterparty in exchange for cash of $555 million. The forward sale could have also been settled at December 31, 2019, with delivery of approximately $25 million of cash or approximately 0.3 million shares of common stock to the counterparty, if Ameren had elected to net cash or net share, respectively.
The forward sale agreement has been classified as an equity transaction because it is indexed to Ameren’s option, newly issued shares, treasury shares,common stock, physical settlement is within Ameren’s control, and the other requirements necessary for equity classification were met. As a result of the equity classification, no gain or shares purchasedloss will be recognized within earnings due to subsequent changes in the open market or in privately negotiated transactions.
From 2015 through 2017, Ameren shares for its DRPlus and its 401(k) plans were purchased infair value of the open market.
Ameren Missouriforward sale agreement. If the average price of Ameren’s common stock exceeds the adjusted forward sale price during a quarterly period, the forward sale agreement could have a dilutive effect on earnings per share.
In June 2017,September 2019, Ameren Missouri issued $400$450 million of 2.95%2.50% senior securedunsecured notes due June 2027,September 2024, with interest payable semiannually on JuneMarch 15 and DecemberSeptember 15 of each year, beginning DecemberMarch 15, 2017.2020. Ameren Missouri received net proceeds of $396$447 million, which were used in conjunction with other available funds, to repay at maturity $425 million of outstanding short-term debt.
Ameren Missouri’s 6.40% senior secured notes in June 2017.Missouri
In February 2016, $2602020, $85 million principal amount of Ameren Missouri’s 5.40%5.00% senior secured notes matured and were repaid with cash on hand and commercial paper borrowings.
In June 2016,March 2019, Ameren Missouri issued $150$450 million of 3.65% senior secured notes3.50% first mortgage bonds due in April 2045,March 2029, with interest payable semiannually in Aprilon March 15 and OctoberSeptember 15 of each year, beginning in October 2016.September 15, 2019. Ameren Missouri received net proceeds of $148$447 million, from the June 2016 issuance, which waswere used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $114$329 million of its 4.75%6.70% senior secured notes that matured February 1, 2019.
In June and July 2019, all of the 1992 Series bonds, 1998 Series A bonds, 1998 Series B bonds, and 1998 Series C bonds issued by the Missouri Environmental Authority on behalf of Ameren Missouri were subject to purchase in lieu of redemption or a mandatory tender as a result of a change in the method of determining the interest rates on the bonds. The interest rate method of each of the series of bonds, as well as Ameren Missouri’s first mortgage bonds that collaterally secure each of the series of bonds, was changed from a variable rate to a fixed rate. Upon the change in the method of determining the interest rate, the bonds, totaling $207 million, were remarketed to new investors. The following table provides additional information on the bonds:
|
| | | | |
| | 1992 Series | 1998 Series A | 1998 Series B | 1998 Series C |
| Transaction month | June 2019 | July 2019 | July 2019 | June 2019 |
| Principal amount | $47 | $60 | $50 | $50 |
| Fixed interest rate | 1.60% | 2.90% | 2.90% | 2.75% |
Variable interest rate(a) | 2.58% | 3.43% | 3.57% | 3.43% |
| Maturity | December 2022 | September 2033 | September 2033 | September 2033 |
| Interest payment dates | June 1 and December 1 | March 1 and September 1 | March 1 and September 1 | March 1 and September 1 |
| Initial interest payment date | December 2019 | September 2019 | September 2019 | September 2019 |
| |
| (a) | Represents the variable interest rate of the bonds effective prior to the change in method of determining the interest rate. |
In October 2019, Ameren Missouri issued $330 million of 3.25% first mortgage bonds due October 2049, with interest payable semiannually on April 2015.1 and October 1 of each year, beginning April 1, 2020. Ameren Missouri received net proceeds of $326 million, which were used to repay $244 million of its 5.10% senior unsecured notes due October 1, 2019, with the remaining proceeds used to repay a portion of its short-term debt.
In October 2019, Ameren Missouri redeemed the remaining amount outstanding of its 5.45% first mortgage bonds due 2028 for less than $1 million.
In April 2018, Ameren Missouri issued $425 million of 4.00% first mortgage bonds due April 2048, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2018. Ameren Missouri received net proceeds of $419 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $179 million of its 6.00% senior secured notes that matured April 1, 2018.
In August 2018, $199 million principal amount of Ameren Missouri’s 5.10% senior secured notes matured and were repaid with cash on hand.
For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
Ameren Illinois
In November 2017,2006, Ameren Illinois issued $500purchased all $17 million of 3.70%the 1993 Series B-1 bonds due 2028 issued by the Illinois Finance Authority on behalf of Ameren Illinois pursuant to a mandatory tender. Ameren Illinois’ 1993 Series B-1 senior unsecured notes due 2028 were not extinguished and remained as “Long-term debt, net” on Ameren’s and Ameren Illinois’ balance sheets. In September 2019, Ameren Illinois exchanged its bond investments for the extinguishment of its senior unsecured notes.
In September 2019, Ameren Illinois redeemed the remaining amount outstanding of its 5.70% first mortgage bonds due December 2047,2024 for less than $1 million. Additionally, in October 2019, Ameren Illinois redeemed the remaining amount outstanding of its 5.90% first mortgage bonds due 2023 for less than $1 million. Following the redemption of the 5.90% first mortgage bonds, Ameren Illinois collaterally secured its 6.70% senior secured notes due 2036 with first mortgage bonds issued under its mortgage indenture.
In November 2019, Ameren Illinois issued $300 million of 3.25% first mortgage bonds due March 2050, with interest payable semiannually on June 1March 15 and December 1September 15 of each year, beginning June 1,March 15, 2020. Ameren Illinois received net proceeds of $296 million, which were used to repay outstanding short-term debt.
In May 2018, Ameren Illinois issued $430 million of 3.80% first mortgage bonds due May 2028, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2018. Ameren Illinois received net proceeds of $492$427 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $250$144 million of its 6.125%6.25% senior secured notes that matured in November 2017.April 1, 2018.
In June 2016, Ameren Illinois’ $54 million principal amount of 6.20% senior secured notes and $75 million principal amount of 6.25% senior secured notes matured and were repaid with commercial paper borrowings.
In December 2016,November 2018, Ameren Illinois issued $240$500 million of 4.15% senior secured notes4.50% first mortgage bonds due in March 2046,2049, with interest payable semiannually inon March 15 and September 15 of each year, beginning in March 2017.15, 2019. Ameren Illinois received net proceeds of $245$495 million, from the issuance, which waswere used to repay a portionoutstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $313 million of its short-term debt.9.75% senior secured notes that matured November 15, 2018.
For information on Ameren Illinois’ capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
ATXI
In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes, due 2050, with interest payable semiannually on the last day of February and August of each year, beginning February 28, 2018, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes, which were used by ATXI to repay existing short-term and long-term affiliate debt.
ATXI may prepay at any time not less than 5% of the principal amount of notes then outstanding at 100% of the principal amount plus a make-whole premium. In the event of a change of control, as defined in the agreement, each holder of notes may require ATXI to prepay the entire unpaid principal amount of the notes held by such holder at a price equal to 100% of the principal amount of such notes together with accrued and unpaid interest thereon.
Indenture Provisions and Other Covenants
Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges, dividend coverage ratios, and bonds and preferred stock issuable as of December 31, 20172019, at an assumed interest rate of 5% and dividend rate of 6%.
| | | | Required Interest Coverage Ratio(a) | Actual Interest Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend Coverage Ratio | Preferred Stock Issuable | | Required Interest Coverage Ratio(a) | Actual Interest Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend Coverage Ratio | Preferred Stock Issuable | |
| Ameren Missouri | >2.0 | 4.8 |
| $ | 4,222 |
| | >2.5 | 95.4 |
| $ | 2,118 |
| | >2.0 | 4.0 |
| $ | 5,251 |
| | >2.5 | 125.7 |
| $ | 2,808 |
| |
| Ameren Illinois | >2.0 | 7.1 |
| 4,119 |
| (d) | >1.5 | 2.9 |
| 203 |
| (e) | >2.0 | 6.8 |
| 6,668 |
| | >1.5 | 3.2 |
| 203 |
| (d) |
| |
| (a) | Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. |
| |
| (b) | Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $1,6292,358 million and $529$643 million at Ameren Missouri and Ameren Illinois, respectively. |
| |
| (c) | Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. |
| |
| (d) | Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under its 1992 mortgage indenture. |
| |
(e) | Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation. |
Ameren’s indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million, or (2) the acceleration upon default of the maturity of any Ameren
indebtedness in excess of $25 million under any indebtedness agreement, including borrowings under the Credit Agreements or the Ameren commercial paper program, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.
Ameren Missouri and Ameren Illinois and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on itstheir respective stock unless, among other things, itstheir respective earnings and earned surplus are sufficient to declare and pay a dividend after provision isprovisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois has made a commitment to the FERC to maintain a minimum 30% ratio of common stock equity to total capitalization. As of December 31, 2017,2019, using the FERC-agreed upon calculation method, Ameren Illinois’ ratio of common stock equity to total capitalization was 51%.
ATXI’s note purchase agreement includes financial covenants that require ATXI not to permit at any time (1) debt to exceed 70% of total capitalization or (2) secured debt to exceed 10% of total assets. The note purchase agreement also contains restrictive covenants that, among other things, restrict the ability of ATXI to (1) enter into certain transactions with affiliates; (2) consolidate, merge, transfer or lease all or substantially all of its assets; and (3) create liens.
At December 31, 2017,2019, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement. In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable requirements in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2017,2019, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business,forward sale agreement relating to common stock, variable interest entities, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.
NOTE 6 – OTHER INCOME, AND EXPENSESNET
The following table presents the components of “Other Income, and Expenses”Net” in the Ameren Companies’ statements of income for the years ended December 31, 2017, 2016,2019, 2018, and 2015:2017:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Ameren: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 28 |
| | $ | 36 |
| | $ | 24 |
|
| Interest income on industrial development revenue bonds | 25 |
| | 26 |
| | 26 |
|
| Other interest income | 8 |
| | 7 |
| | 8 |
|
| Non-service cost components of net periodic benefit income | 90 |
| (a) | 70 |
| (a) | 44 |
|
| Other income | 6 |
| | 8 |
| | 5 |
|
| Charitable donations | (12 | ) | | (33 | ) | | (8 | ) |
| Other expense | (15 | ) | | (12 | ) | | (13 | ) |
| Total Other Income, Net | $ | 130 |
| | $ | 102 |
| | $ | 86 |
|
| Ameren Missouri: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 19 |
| | $ | 27 |
| | $ | 21 |
|
| Interest income on industrial development revenue bonds | 25 |
| | 26 |
| | 26 |
|
| Other interest income | 1 |
| | 2 |
| | 1 |
|
| Non-service cost components of net periodic benefit income | 18 |
| (a) | 17 |
| (a) | 22 |
|
| Other income | 5 |
| | 4 |
| | 3 |
|
| Charitable donations | (3 | ) | | (14 | ) | | (2 | ) |
| Other expense | (7 | ) | | (6 | ) | | (6 | ) |
| Total Other Income, Net | $ | 58 |
| | $ | 56 |
| | $ | 65 |
|
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
Ameren:(a) | | | | | | |
| Miscellaneous income: | | | | | | |
| Allowance for equity funds used during construction | $ | 24 |
| | $ | 27 |
| | $ | 30 |
| |
| Interest income on industrial development revenue bonds | 26 |
| | 27 |
| | 27 |
| |
Interest income(b) | 8 |
| | 13 |
| | 14 |
| |
| Other | 1 |
| | 7 |
| | 3 |
| |
| Total miscellaneous income | $ | 59 |
| | $ | 74 |
| | $ | 74 |
| |
| Miscellaneous expense: | | | | | | |
| Donations | $ | 8 |
| | $ | 16 |
| | $ | 15 |
| |
| Other | 13 |
| | 16 |
| | 15 |
| |
| Total miscellaneous expense | $ | 21 |
| | $ | 32 |
| | $ | 30 |
| |
| Ameren Missouri: | | | | | | |
| Miscellaneous income: | | | | | | |
| Allowance for equity funds used during construction | $ | 21 |
| | $ | 23 |
| | $ | 22 |
| |
| Interest income on industrial development revenue bonds | 26 |
| | 27 |
| | 27 |
| |
| Interest income | 1 |
| | 1 |
| | 1 |
| |
| Other | — |
| | 1 |
| | 2 |
| |
| Total miscellaneous income | $ | 48 |
| | $ | 52 |
| | $ | 52 |
| |
| Miscellaneous expense: | | | | | | |
| Donations | $ | 2 |
| | $ | 4 |
| | $ | 5 |
| |
| Other | 6 |
| | 6 |
| | 6 |
| |
| Total miscellaneous expense | $ | 8 |
| | $ | 10 |
| | $ | 11 |
| |
| Ameren Illinois: | | | | | | |
| Miscellaneous income: | | | | | | |
| Allowance for equity funds used during construction | $ | 3 |
| | $ | 4 |
| | $ | 8 |
| |
Interest income(b) | 7 |
| | 12 |
| | 12 |
| |
| Other | 1 |
| | 5 |
| | 1 |
| |
| Total miscellaneous income | $ | 11 |
| | $ | 21 |
| | $ | 21 |
| |
| Miscellaneous expense: | | | | | | |
| Donations | $ | 5 |
| | $ | 6 |
| | $ | 5 |
| |
| Other | 5 |
| | 6 |
| | 7 |
| |
| Total miscellaneous expense | $ | 10 |
| | $ | 12 |
| | $ | 12 |
| |
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Ameren Illinois: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 9 |
| | $ | 9 |
| | $ | 3 |
|
| Interest income | 6 |
| | 6 |
| | 7 |
|
| Non-service cost components of net periodic benefit income | 47 |
| | 34 |
| | 10 |
|
| Other income | 3 |
| | 3 |
| | 2 |
|
| Charitable donations | (5 | ) | | (6 | ) | | (5 | ) |
| Other expense | (7 | ) | | (4 | ) | | (5 | ) |
| Total Other Income, Net | $ | 53 |
| | $ | 42 |
| | $ | 12 |
|
| |
| (a) | Includes amountsFor the years ended December 31, 2019, and 2018, the non-service cost components of net periodic benefit income were partially offset by a deferral of $29 million and $17 million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren registrantMissouri under GAAP and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | Includes Ameren Illinois’ interest income on the IEIMA revenue requirement reconciliation adjustment regulatory assets.level of such costs included in rates. |
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives to manage the risk of changes in market prices for natural gas, power and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory; and
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.outlays; and
actual off-system sales revenues that differ from anticipated revenues.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2017 and 2016. As of December 31, 2017, these contracts extended through October 2019, March 2023, May 2032, and September 2021 for fuel oils, natural gas, power, and uranium, respectively.
|
| | | | | | | | | | | | |
| | Quantity (in millions, except as indicated) |
| | 2017 | 2016 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
Fuel oils (in gallons)(a) | 28 |
| (b) |
| 28 |
| 30 |
| (b) |
| 30 |
|
| Natural gas (in mmbtu) | 24 |
| 139 |
| 163 |
| 25 |
| 129 |
| 154 |
|
| Power (in megawatthours) | 3 |
| 9 |
| 12 |
| 1 |
| 9 |
| 10 |
|
| Uranium (pounds in thousands) | 370 |
| (b) |
| 370 |
| 345 |
| (b) |
| 345 |
|
| |
(a) | Consists of ultra-low-sulfur diesel products. |
All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 – Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery. The following disclosures exclude NPNS contracts and other non-derivative commodity contracts that are accounted for under the accrual method of accounting.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of December 31, 20172019 and 2016,2018, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Cash flows for all derivative financial instruments are classified in cash flows from operating activities.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2019 and 2018. As of December 31, 2019, these contracts extended through October 2022, March 2024, May 2032, and March 2023 for fuel oils, natural gas, power, and uranium, respectively.
|
| | | | | | | | | | | | |
| | Quantity (in millions, except as indicated) |
| | 2019 | 2018 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
| Fuel oils (in gallons) | 58 |
| — |
| 58 |
| 66 |
| — |
| 66 |
|
| Natural gas (in mmbtu) | 20 |
| 136 |
| 156 |
| 19 |
| 154 |
| 173 |
|
| Power (in megawatthours) | 5 |
| 7 |
| 12 |
| 1 |
| 8 |
| 9 |
|
| Uranium (pounds in thousands) | 565 |
| — |
| 565 |
| 380 |
| — |
| 380 |
|
The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of December 31, 20172019 and 20162018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | | 2018 |
| Commodity | Balance Sheet Location | | Ameren Missouri | | | Ameren Illinois | | | Ameren | | | | Ameren Missouri | | | Ameren Illinois | | | Ameren |
| Fuel oils | Other current assets | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
| | Other assets | | 2 |
| | | — |
| | | 2 |
| | | | 5 |
| | | — |
| | | 5 |
|
| Natural gas | Other current assets | | — |
| | | 3 |
| | | 3 |
| | | | — |
| | | 1 |
| | | 1 |
|
| | Other assets | | — |
| | | 1 |
| | | 1 |
| | | | — |
| | | 2 |
| | | 2 |
|
| Power | Other current assets | | 14 |
| | | — |
| | | 14 |
| | | | 4 |
| | | — |
| | | 4 |
|
| | Other assets | | 2 |
| | | — |
| | | 2 |
| | | | — |
| | | — |
| | | — |
|
| | Total assets | $ | 22 |
| | $ | 4 |
| | $ | 26 |
| | | $ | 12 |
| | $ | 3 |
| | $ | 15 |
|
| Fuel oils | Other current liabilities | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | 4 |
| | $ | — |
| | $ | 4 |
|
| | Other deferred credits and liabilities | | 3 |
| | | — |
| | | 3 |
| | | | 9 |
| | | — |
| | | 9 |
|
| Natural gas | Other current liabilities | | 1 |
| | | 12 |
| | | 13 |
| | | | 4 |
| | | 8 |
| | | 12 |
|
| | Other deferred credits and liabilities | | 1 |
| | | 6 |
| | | 7 |
| | | | 1 |
| | | 6 |
| | | 7 |
|
| Power | Other current liabilities | | 2 |
| | | 17 |
| | | 19 |
| | | | 4 |
| | | 14 |
| | | 18 |
|
| | Other deferred credits and liabilities | | 1 |
| | | 207 |
| | | 208 |
| | | | — |
| | | 169 |
| | | 169 |
|
| Uranium | Other deferred credits and liabilities | | 1 |
| | | — |
| | | 1 |
| | | | — |
| | | — |
| | | — |
|
| | Total liabilities | $ | 13 |
| | $ | 242 |
| | $ | 255 |
| | | $ | 22 |
| | $ | 197 |
| | $ | 219 |
|
|
| | | | | | | | | | | |
| | Balance Sheet Location | | Ameren Missouri | | Ameren Illinois | | Ameren | |
| 2017 | | | | | | | | |
| Fuel oils | Other current assets | $ | 5 |
| $ | — |
| $ | 5 |
| |
| | Other assets | | 2 |
| | — |
| | 2 |
| |
| Natural gas | Other assets | | 1 |
| | — |
| | 1 |
| |
| Power | Other current assets | | 9 |
| | — |
| | 9 |
| |
| | Total assets (a) | $ | 17 |
| $ | — |
| $ | 17 |
| |
| Natural gas | Other current liabilities | | 5 |
| | 12 |
| | 17 |
| |
| | Other deferred credits and liabilities | | 3 |
| | 10 |
| | 13 |
| |
| Power | Other current liabilities | | 1 |
| | 13 |
| | 14 |
| |
| | Other deferred credits and liabilities | | — |
| | 182 |
| | 182 |
| |
| Uranium | Other deferred credits and liabilities | | — |
| (b) | — |
| | — |
| (b) |
| | Total liabilities (c) | $ | 9 |
| $ | 217 |
| $ | 226 |
| |
| 2016 | | | | | | | | |
| Fuel oils | Other current assets | $ | 2 |
| $ | — |
| $ | 2 |
| |
| | Other assets | | 1 |
| | — |
| | 1 |
| |
| Natural gas | Other current assets | | 1 |
| | 11 |
| | 12 |
| |
| | Other assets | | 1 |
| | 2 |
| | 3 |
| |
| Power | Other current assets | | 9 |
| | — |
| | 9 |
| |
| | Total assets (a) | $ | 14 |
| $ | 13 |
| $ | 27 |
| |
| Fuel oils | Other current liabilities | $ | 5 |
| $ | — |
| $ | 5 |
| |
| Natural gas | Other current liabilities | | 1 |
| | 3 |
| | 4 |
| |
| | Other deferred credits and liabilities | | 5 |
| | 5 |
| | 10 |
| |
| Power | Other current liabilities | | 3 |
| | 12 |
| | 15 |
| |
| | Other deferred credits and liabilities | | — |
| | 173 |
| | 173 |
| |
| Uranium | Other deferred credits and liabilities | | 4 |
| | — |
| | 4 |
| |
| | Total liabilities (c) | $ | 18 |
| $ | 193 |
| $ | 211 |
| |
| |
(a) | The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability. |
| |
(b) | Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet. |
| |
(c) | The cumulative amount of pretax net losses on all derivative instruments is deferred as a regulatory asset. |
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges; these contracts have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master netting arrangements or similar agreements, and reporting daily exposure to senior management.
We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar agreement level by counterparty.
The Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement at the gross amounts on the balance sheet. However, if the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at December 31, 20172019 and 2016.2018.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. We calculate maximum exposures based on the gross fair value of financial instruments, including NPNS and other accrual contracts. These exposures are calculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. As of December 31, 2017,2019, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contractsCertain of our derivative instruments contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded below investment grade, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2017, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on December 31, 2017, and (2) those counterparties with rights to do so requested collateral. As of December 31, 2019, the aggregate fair value of derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require were each immaterial to Ameren, Ameren Missouri, and Ameren Illinois.
|
| | | | | | | | | | | |
| | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| 2017 | | | | | |
| Ameren Missouri | $ | 55 |
| | $ | 3 |
| | $ | 44 |
|
| Ameren Illinois | 43 |
| | — |
| | 38 |
|
| Ameren | $ | 98 |
| | $ | 3 |
| | $ | 82 |
|
| |
(a) | Before consideration of master netting arrangements or similar agreements and including NPNS and other accrual contract exposures. |
| |
(b) | As collateral requirements with certain counterparties are based on master netting arrangements or similar agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such arrangements. |
NOTE 8 – FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use
various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1:1 (quoted prices in active markets for identical assets or liabilities): Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives, and assets, including cash and cash equivalents, and listed equity securities, such as those held in Ameren Missouri’s nuclear decommissioning trust fund.securities.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants, and the trustee and investment managers. The S&P 500 index comprises stocks of large-capitalization companies.
Level 2 (significant other observable inputs): Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including United States Treasury and agency securities, corporate bonds and other fixed-income securities, United States Treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.
Fixed income securities are valued by using prices from independent industry-recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed-income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the nuclear decommissioning trust fund are primarily corporate bonds, asset-backed securities, and United States agency bonds.
Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the bid/ask spreads to the midpoints. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoints. The value of natural gas derivative contracts is based upon exchange closing prices without significant unobservable adjustments. The value of power derivativesderivative contracts is based upon exchange closing prices or the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.
Level 3:3 (significant other unobservable inputs): Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, such as certain internal assumptions, quotes or prices from outside sources not supported by a liquid market, or escalationtrend rates. Our development and corroboration process entails reasonableness reviews and an evaluation of all sources to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
The following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and 2016:
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
Level 3 Derivative asset and liability – commodity contracts(a): | | | |
| 2017 | | | | | | | | |
| | Fuel oils | $ | 3 |
| $ | — |
| | Option model | Volatilities(%)(b) | 20 – 26 | 22 |
| | | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.12 – 0.72 | 0.41 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.37 | (e) |
| | Natural Gas | 1 |
| (4 | ) | | Option model | Volatilities(%)(b) | 26 – 46 | 37 |
| |
|
|
| |
| Nodal basis($/mmbtu)(c) | (0.50) – (0.30) | (0.40) |
| |
|
|
| | Discounted cash flow | Nodal basis($/mmbtu)(b) | (1.20) – 0.10 | (1) |
| |
|
|
| |
| Counterparty credit risk(%)(c)(d) | 0.37 – 0.92 | 0.53 |
| |
|
|
| |
| Ameren credit risk(%)(c)(d) | 0.37 | (e) |
| | Power(f) | 8 |
| (196 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 24 – 46 | 28 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (65) – 1,823 | 251 |
| | | | | | | Nodal basis($/MWh)(g) | (10) – 0 | (2) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.28 | (e) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.37 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| 2016 | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| | Option model | Volatilities(%)(b) | 24 – 66 | 28 |
| | | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.13 – 0.22 | 0.15 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | | | Escalation rate(%)(b)(i) | (2) – 2 | 0 |
| | Natural Gas | $ | 1 |
| $ | (1 | ) | | Option model | Volatilities(%)(b) | 31 – 66 | 36 |
| | | | | | | Nodal basis($/mmbtu)(b) | (0.40) – (0.10) | (0.20) |
| | | | | | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.80) – 0 | (0.50) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.13 – 8 | 1 |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | Power(f) | 9 |
| (187 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 26 – 44 | 29 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (71) – 5,270 | 125 |
| | | | | | | Nodal basis($/MWh)(g) | (6) – 0 | (2) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| | Uranium | — |
| (4 | ) | | Option model | Volatilities(%)(b) | 24 | (e) |
|
| | | | | | | | | | | | |
| | Fair Value | | | | | Weighted |
| | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| | | | | Discounted cash flow | Average forward uranium pricing($/pound)(b)
| 22 – 24 | 22 |
| | | | | | Ameren Missouri credit risk(%)(c)(d)
| 0.38 | (e) |
| |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
| |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
| |
(d) | Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances. |
| |
(f) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2021. Valuations beyond 2021 use fundamentally modeled pricing by month for peak and off-peak demand. |
| |
(g) | Ameren Missouri and Ameren Illinois power contracts respond differently to unobservable input changes because of their opposing positions. |
| |
(h) | Escalation rate applies to power prices in 2031 and beyond. |
| |
(i) | Escalation rate applies to fuel oil prices in 2019 and beyond. |
We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in 2017, 2016,2019, 2018, or 2015.2017. At December 31, 20172019 and 2016,2018, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2017:2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2019 | | | December 31, 2018 | |
| | | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | | | | | | | | | | |
| Ameren | Derivative assets – commodity contracts: | | | | | | | | | | | |
| | Fuel oils | $ | — |
| $ | — |
| $ | 6 |
| $ | 6 |
| | | $ | 1 |
| $ | — |
| $ | 7 |
| $ | 8 |
| |
| | Natural gas | — |
| 1 |
| 3 |
| 4 |
| | | — |
| 2 |
| 1 |
| 3 |
| |
| | Power | — |
| 2 |
| 14 |
| 16 |
| | | — |
| 1 |
| 3 |
| 4 |
| |
| | Total derivative assets – commodity contracts | $ | — |
| $ | 3 |
| $ | 23 |
| $ | 26 |
| | | $ | 1 |
| $ | 3 |
| $ | 11 |
| $ | 15 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | Equity securities: | | | | | | | | | | | |
| | U.S. large capitalization | $ | 569 |
| $ | — |
| $ | — |
| $ | 569 |
| | | $ | 427 |
| $ | — |
| $ | — |
| $ | 427 |
| |
| | Debt securities: | | | | | | | | | | | |
| | U.S. Treasury and agency securities | — |
| 107 |
| — |
| 107 |
| | | — |
| 148 |
| — |
| 148 |
| |
| | Corporate bonds | — |
| 93 |
| — |
| 93 |
| | | — |
| 72 |
| — |
| 72 |
| |
| | Other | — |
| 73 |
| — |
| 73 |
| | | — |
| 32 |
| — |
| 32 |
| |
| | Total nuclear decommissioning trust fund | $ | 569 |
| $ | 273 |
| $ | — |
| $ | 842 |
| (a) | | $ | 427 |
| $ | 252 |
| $ | — |
| $ | 679 |
| (a) |
| | Total Ameren | $ | 569 |
| $ | 276 |
| $ | 23 |
| $ | 868 |
| | | $ | 428 |
| $ | 255 |
| $ | 11 |
| $ | 694 |
| |
| Ameren Missouri | Derivative assets – commodity contracts: | | | | | | | | | | | |
| | Fuel oils | $ | — |
| $ | — |
| $ | 6 |
| $ | 6 |
| | | $ | 1 |
| $ | — |
| $ | 7 |
| $ | 8 |
| |
| | Power | — |
| 2 |
| 14 |
| 16 |
| | | — |
| 1 |
| 3 |
| 4 |
| |
| | Total derivative assets – commodity contracts | $ | — |
| $ | 2 |
| $ | 20 |
| $ | 22 |
| | | $ | 1 |
| $ | 1 |
| $ | 10 |
| $ | 12 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | Equity securities: | | | | | | | | | | | |
| | U.S. large capitalization | $ | 569 |
| $ | — |
| $ | — |
| $ | 569 |
| | | $ | 427 |
| $ | — |
| $ | — |
| $ | 427 |
| |
| | Debt securities: | | | | | | | | | | | |
| | U.S. Treasury and agency securities | — |
| 107 |
| — |
| 107 |
| | | — |
| 148 |
| — |
| 148 |
| |
| | Corporate bonds | — |
| 93 |
| — |
| 93 |
| | | — |
| 72 |
| — |
| 72 |
| |
| | Other | — |
| 73 |
| — |
| 73 |
| | | — |
| 32 |
| — |
| 32 |
| |
| | Total nuclear decommissioning trust fund | $ | 569 |
| $ | 273 |
| $ | — |
| $ | 842 |
| (a) | | $ | 427 |
| $ | 252 |
| $ | — |
| $ | 679 |
| (a) |
| | Total Ameren Missouri | $ | 569 |
| $ | 275 |
| $ | 20 |
| $ | 864 |
| | | $ | 428 |
| $ | 253 |
| $ | 10 |
| $ | 691 |
| |
| Ameren Illinois | Derivative assets – commodity contracts: | | | | | | | | | | | |
| | Natural gas | $ | — |
| $ | 1 |
| $ | 3 |
| $ | 4 |
| | | $ | — |
| $ | 2 |
| $ | 1 |
| $ | 3 |
| |
| Liabilities: | | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| $ | 6 |
| $ | 7 |
| | | $ | 2 |
| $ | — |
| $ | 11 |
| $ | 13 |
| |
| | Natural gas | 3 |
| 14 |
| 3 |
| 20 |
| | | — |
| 15 |
| 4 |
| 19 |
| |
| | Power | — |
| 2 |
| 225 |
| 227 |
| | | — |
| 1 |
| 186 |
| 187 |
| |
| | Uranium | — |
| — |
| 1 |
| 1 |
| | | — |
| — |
| — |
| — |
| |
| | Total Ameren | $ | 4 |
| $ | 16 |
| $ | 235 |
| $ | 255 |
| | | $ | 2 |
| $ | 16 |
| $ | 201 |
| $ | 219 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| $ | 6 |
| $ | 7 |
| | | $ | 2 |
| $ | — |
| $ | 11 |
| $ | 13 |
| |
| | Natural gas | — |
| 2 |
| — |
| 2 |
| | | — |
| 5 |
| — |
| 5 |
| |
| | Power | — |
| 2 |
| 1 |
| 3 |
| | | — |
| 1 |
| 3 |
| 4 |
| |
| | Uranium | — |
| — |
| 1 |
| 1 |
| | | — |
| — |
| — |
| — |
| |
| | Total Ameren Missouri | $ | 1 |
| $ | 4 |
| $ | 8 |
| $ | 13 |
| | | $ | 2 |
| $ | 6 |
| $ | 14 |
| $ | 22 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| | Natural gas | $ | 3 |
| $ | 12 |
| $ | 3 |
| $ | 18 |
| | | $ | — |
| $ | 10 |
| $ | 4 |
| $ | 14 |
| |
| | Power | — |
| — |
| 224 |
| 224 |
| | | — |
| — |
| 183 |
| 183 |
| |
| | Total Ameren Illinois | $ | 3 |
| $ | 12 |
| $ | 227 |
| $ | 242 |
| | | $ | — |
| $ | 10 |
| $ | 187 |
| $ | 197 |
| |
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| Assets: | | | | | | | | | | |
| Ameren | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | Total Ameren | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | Total Ameren Missouri | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Liabilities: | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | 1 |
| | 25 |
| | 4 |
| | 30 |
| |
| | Power | | — |
| | — |
| | 196 |
| | 196 |
| |
| | Total Ameren | | $ | 1 |
| | $ | 25 |
| | $ | 200 |
| | $ | 226 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | — |
| | 7 |
| | 1 |
| | 8 |
| |
| | Power | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Total Ameren Missouri | | $ | — |
| | $ | 7 |
| | $ | 2 |
| | $ | 9 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | 1 |
| | $ | 18 |
| | $ | 3 |
| | $ | 22 |
| |
| | Power | | — |
| | — |
| | 195 |
| | 195 |
| |
| | Total Ameren Illinois | | $ | 1 |
| | $ | 18 |
| | $ | 198 |
| | $ | 217 |
| |
| |
| (a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(b) | Balance excludes $2$5 million and $5 million of cash and cash equivalents, receivables, payables, and accrued income, net.net for December 31, 2019 and 2018, respectively. |
The following table setsSee Note 10 – Retirement Benefits for tables that set forth, by level within the fair value hierarchy, ourAmeren’s pension and postretirement plan assets as of December 31, 2019 and 2018.
Level 3 fuel oils, natural gas and uranium derivative contract assets and liabilities measured at fair value on a recurring basis aswere immaterial for all periods presented. The following table presents the fair value reconciliation of December 31, 2016:
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| Assets: | | | | | | | | | | |
| Ameren | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Natural gas | | 2 |
| | 12 |
| | 1 |
| | 15 |
| |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 12 |
| | $ | 11 |
| | $ | 27 |
| |
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | Total Ameren | | $ | 413 |
| | $ | 208 |
| | $ | 11 |
| | $ | 632 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Natural gas | | — |
| | 1 |
| | 1 |
| | 2 |
| |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 2 |
| | $ | 1 |
| | $ | 11 |
| | $ | 14 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | Total Ameren Missouri | | $ | 411 |
| | $ | 197 |
| | $ | 11 |
| | $ | 619 |
| |
| Ameren Illinois | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | 2 |
| | $ | 11 |
| | $ | — |
| | $ | 13 |
| |
| Liabilities: | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| |
| | Power | | — |
| | 1 |
| | 187 |
| | 188 |
| |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren | | $ | 5 |
| | $ | 14 |
| | $ | 192 |
| | $ | 211 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | — |
| | 6 |
| | — |
| | 6 |
| |
| | Power | | — |
| | 1 |
| | 2 |
| | 3 |
| |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren Missouri | | $ | 5 |
| | $ | 7 |
| | $ | 6 |
| | $ | 18 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 7 |
| | $ | 1 |
| | $ | 8 |
| |
| | Power | | — |
| | — |
| | 185 |
| | 185 |
| |
| | Total Ameren Illinois | | $ | — |
| | $ | 7 |
| | $ | 186 |
| | $ | 193 |
| |
| |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
All costs related to financialLevel 3 power derivative contract assets and liabilities classified asmeasured at fair value on a recurring basis for the years ended December 31, 2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | | |
| | 2019 | | | 2018 |
| | Ameren Missouri | Ameren Illinois | Ameren | | | Ameren Missouri | Ameren Illinois | Ameren |
| Beginning balance at January 1 | $ | — |
| $ | (183 | ) | $ | (183 | ) | | | $ | 7 |
| $ | (195 | ) | $ | (188 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | 23 |
| (56 | ) | (33 | ) | | | (6 | ) | — |
| (6 | ) |
| Purchases | — |
| — |
| — |
| | | 5 |
| — |
| 5 |
|
| Settlements | (7 | ) | 15 |
| 8 |
| | | (5 | ) | 12 |
| 7 |
|
| Transfers out of Level 3 | (3 | ) | — |
| (3 | ) | | | (1 | ) | — |
| (1 | ) |
| Ending balance at December 31 | $ | 13 |
| $ | (224 | ) | $ | (211 | ) | | | $ | — |
| $ | (183 | ) | $ | (183 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | 12 |
| $ | (54 | ) | $ | (42 | ) | | | $ | (1 | ) | $ | (2 | ) | $ | (3 | ) |
For the years ended December 31, 2019 and 2018, there were no material transfers between fair value hierarchy levels.
All gains or losses related to our Level 3 in the fair value hierarchyderivative commodity contracts are expected to be recoverablerecovered or returned through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. For
The following table describes the years ended December 31, 2017valuation techniques and 2016, the balances and changes insignificant unobservable inputs utilized for the fair value of our Level 3 financialpower derivative contract assets and liabilities associated with fuel oils, natural gas,as of December 31, 2019 and uranium were immaterial.2018:
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted Average(b) |
| | Commodity | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input(a) | Range |
| 2019 | Power(c) | $ | 14 |
| $ | (225 | ) |
| Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh) | 22 – 34 | 25 |
| | | | |
| | Nodal basis($/MWh) | (6) – 0 | (2) |
| | | | |
|
| Trend rate(%) | (1) – 0 | 0 |
| 2018 | Power(d) | $ | 3 |
| $ | (186 | ) |
| Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh) | 23 – 39 | 28 |
| | | | | | | Nodal basis($/MWh) | (9) – 0 | (2) |
| | | | |
| Fundamental energy production model | Estimated future natural gas prices($/mmbtu) | 3 – 4 | 3 |
| |
| (a) | Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement. |
| |
| (b) | Unobservable inputs were weighted by relative fair value. |
| |
| (c) | Valuations through 2028 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2028 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials. |
| |
| (d) | Valuations through 2022 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2022 use a fundamental energy production model incorporating estimated future natural gas prices. |
The following table summarizes the changes insets forth, by level within the fair value hierarchy, the carrying amount and fair value of power financial assets and liabilities classified as Level 3 in thedisclosed, but not carried, at fair value hierarchy:
|
| | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| For the year ended December 31, 2016 | | | | | | |
| Beginning balance at January 1, 2016 | $ | 16 |
| $ | (170 | ) | $ | (154 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | (1 | ) | | (29 | ) | | (30 | ) |
| Purchases | | 13 |
| | — |
| | 13 |
|
| Settlements | | (21 | ) | | 14 |
| | (7 | ) |
| Ending balance at December 31, 2016 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2016 | $ | — |
| $ | (27 | ) | $ | (27 | ) |
| For the year ended December 31, 2017 | | | | | | |
| Beginning balance at January 1, 2017 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | (4 | ) | | (21 | ) | | (25 | ) |
| Purchases | | 14 |
| | — |
| | 14 |
|
| Sales | | 1 |
| | — |
| | 1 |
|
| Settlements | | (11 | ) | | 11 |
| | — |
|
| Ending balance at December 31, 2017 | $ | 7 |
| $ | (195 | ) | $ | (188 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2017 | $ | — |
| $ | (22 | ) | $ | (22 | ) |
Transfers into or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level, but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3, but were recategorized to a higher level because the lowest significant input became observable during the period. For the years ended December 31, 2017 and 2016, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or Level 2 and Level 3 related to derivative commodity contracts.
See Note 10 – Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 2017, as well as a table summarizing the changes in Level 3 plan assets during 2017.
The Ameren Companies’ carrying amounts of cash2019 and cash equivalents, accounts receivable, unbilled revenue, accounts payable, and other current financial instruments approximate fair value because of the short-term nature of these instruments. They are considered to be Level 1 in the fair value hierarchy. The Ameren Companies’ short-term borrowings also approximate fair value because of their short-term nature. Ameren and Ameren Illinois have company-owned life insurance that is recorded in “Other Assets” on the respective balance sheet and measured at net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy. As of December 31, 2017 and 2016, the net asset value of Ameren (parent)’s company-owned life insurance was $136 million and $123 million, respectively. As of December 31, 2017 and 2016, the net asset value of Ameren Illinois’ company owned life insurance was $9 million and $8 million, respectively.
Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and estimated fair values of our long-term debt, capital lease obligations, and preferred stock at December 31, 2017 and 2016:2018:
|
| | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Ameren: | | | | | | | |
Long-term debt and capital lease obligations (including current portion)(a) | $ | 7,935 |
| | $ | 8,531 |
| | $ | 7,276 |
| | $ | 7,772 |
|
Preferred stock(b) | 142 |
| | 131 |
| | 142 |
| | 131 |
|
| Ameren Missouri: | | | | | | | |
Long-term debt and capital lease obligations (including current portion)(a) | $ | 3,961 |
| | $ | 4,348 |
| | $ | 3,994 |
| | $ | 4,304 |
|
| Preferred stock | 80 |
| | 80 |
| | 80 |
| | 79 |
|
| Ameren Illinois: | | | | | | | |
| Long-term debt (including current portion) | $ | 2,830 |
| | $ | 3,028 |
| | $ | 2,588 |
| | $ | 2,765 |
|
| Preferred stock | 62 |
| | 51 |
| | 62 |
| | 52 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Carrying Amount | | Fair Value | | |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Ameren: | December 31, 2019 |
| Cash, cash equivalents, and restricted cash | $ | 176 |
| | $ | 176 |
| | $ | — |
| | $ | — |
| | $ | 176 |
|
Investments in industrial development revenue bonds(a) | 263 |
| | — |
| | 263 |
| | — |
| | 263 |
|
| Short-term debt | 440 |
| | — |
| | 440 |
| | — |
| | 440 |
|
Long-term debt (including current portion)(a) | 9,357 |
| (b) | — |
| | 9,957 |
| | 484 |
| (c) | 10,441 |
|
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 39 |
| | $ | 39 |
| | $ | — |
| | $ | — |
| | $ | 39 |
|
Investments in industrial development revenue bonds(a) | 263 |
| | — |
| | 263 |
| | — |
| | 263 |
|
| Short-term debt | 234 |
| | — |
| | 234 |
| | — |
| | 234 |
|
Long-term debt (including current portion)(a) | 4,190 |
| (b) | — |
| | 4,772 |
| | — |
| | 4,772 |
|
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 125 |
| | $ | 125 |
| | $ | — |
| | $ | — |
| | $ | 125 |
|
| Short-term debt | 53 |
| | — |
| | 53 |
| | — |
| | 53 |
|
| Long-term debt (including current portion) | 3,575 |
| (b) | — |
| | 4,019 |
| | — |
| | 4,019 |
|
| | December 31, 2018 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 107 |
| | $ | 107 |
| | $ | — |
| | $ | — |
| | $ | 107 |
|
Investments in industrial development revenue bonds(a) | 270 |
| | — |
| | 270 |
| | — |
| | 270 |
|
| Short-term debt | 597 |
| | — |
| | 597 |
| | — |
| | 597 |
|
Long-term debt (including current portion)(a) | 8,439 |
| (b) | — |
| | 8,240 |
| | 429 |
| (c) | 8,669 |
|
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
Investments in industrial development revenue bonds(a) | 270 |
| | — |
| | 270 |
| | — |
| | 270 |
|
| Short-term debt | 55 |
| | — |
| | 55 |
| | — |
| | 55 |
|
Long-term debt (including current portion)(a) | 3,998 |
| (b) | — |
| | 4,156 |
| | — |
| | 4,156 |
|
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 80 |
| | $ | 80 |
| | $ | — |
| | $ | — |
| | $ | 80 |
|
| Short-term debt | 72 |
| | — |
| | 72 |
| | — |
| | 72 |
|
| Long-term debt (including current portion) | 3,296 |
| (b) | — |
| | 3,391 |
| | — |
| | 3,391 |
|
| |
| (a) | Ameren and Ameren Missouri have two CTs under separate capital lease agreements. The capital lease obligations as of December 31, 2017 and 2016, were $276 million and $282 million, respectively. In addition, Ameren and Ameren Missouri have investments in debt securities,industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets”Assets,” that are relatedequal to the capital lease obligation CTs fromfinance obligations for the city of Bowling GreenPeno Creek and Audrain County.CT energy centers. As of December 31, 20172019 and 2016,2018, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value of these investments approximate carrying value of $276 million and $282 million, respectively.value. |
| |
| (b) | Preferred stock is recorded in “Noncontrolling Interests” onIncluded unamortized debt issuance costs, which were excluded from the consolidated balance sheet.fair value measurement, of $72 million, $30 million, and $34 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2019. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $58 million, $22 million, and $31 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2018. |
| |
| (c) | The Level 3 fair value amount consists of ATXI’s senior unsecured notes. |
NOTE 9 – CALLAWAY ENERGY CENTER
Spent Nuclear Fuel
Under the NWPA,Nuclear Waste Policy Act of 1982, as amended, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy centerEnergy Center and other commercial nuclear energy centers. The NWPA established the fee paid by Ameren Missouri and other utilities that own and operate those energy centers to the federal government for disposing of the spent nuclear fuel at one mill, (one-tenth of one cent), for each kilowatthour generated and sold by those plants. The NWPA also requires the DOE to review the nuclear waste fee annually against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA,act, Ameren Missouri and other utilities have entered into standard contracts with the DOE. Consistent with the NWPA and its standard contract,DOE, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998, Ameren Missouri had historically collected one mill from its electric customers for each kilowatthour of electricity that it generated and sold from its Callaway energy center. Because1998. However, the federal government is not meeting its disposal obligation, the collection of this fee was suspended in May 2014. The DOE’s delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operations of the energy center.
As a result of the DOE’s failureDOE failed to fulfill its contractualdisposal obligations, and Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. TheAmeren Missouri’s lawsuit against the DOE resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. Ameren Missouri received reimbursements from the DOE of $21 million, $11 million, and $3 million $24 million,in 2019, 2018, and $14 million in 2017, 2016, and 2015, respectively. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.
Supplier The DOE’s delay in carrying out its obligation to dispose of Fuel Assemblies
The Callaway energy center usesspent nuclear fuel assemblies fabricated by Westinghouse, which is the only NRC-licensed supplier authorized to provide fuel assemblies tofrom the Callaway energy center. DuringEnergy Center is not expected to adversely affect the first quarter of 2017, Westinghouse filed voluntary petitions for a court-supervised restructuring process under Chapter 11continued operations of the United States Bankruptcy Code. Westinghouse could petition the bankruptcy court to reject Ameren Missouri’s contracts as part of the restructuring process. If the bankruptcy court agrees, this could result in Ameren Missouri not having access to the fuel assemblies necessary to refuel the Callaway energy center in future scheduled refueling and maintenance outages. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, and therefore do not expect any material impact to Ameren Missouri’s operations. However, Ameren and Ameren Missouri could incur material unexpected costs as a result of the Westinghouse bankruptcy, such as the loss of fuel inventory that is stored at Westinghouse’s facility and the cost of replacement power if nuclear fuel assemblies were not available for a future scheduled refueling and maintenance outage. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement.
center.
Decommissioning
Electric rates charged to customers provide for the recovery of the Callaway energy center’sEnergy Center’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over the expected life of the nuclear energy center. Amounts collected from
customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway energy center’sEnergy Center’s decommissioning. It is assumed that the Callaway energy centerEnergy Center site will be eventually decommissioned after its retirement through the immediate dismantlement method and removed from service. The Callaway Energy Center’s operating license expires in 2044. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy centerEnergy Center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Annual decommissioning costs of $7 million are included in the costs used to establish electric rates for Ameren Missouri’s customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center.Energy Center. An updated cost study and funding analysis was filed with the MoPSC in September 2017 and reflected within the ARO. In January 2018, the MoPSC approved no change in electric rates for decommissioning costs based onconsistent with Ameren Missouri’s updated cost study and funding analysis.
The fair value of the trust fund for Ameren Missouri’s Callaway energy centerEnergy Center is reported as “Nuclear decommissioning trust fund” in Ameren’s and Ameren Missouri’s balance sheets. This amount is legally restricted and 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, with an offsetting adjustment to the related regulatory liability. If the assumed return on trust assets is not earned, Ameren Missouri believes that it is probable that any additional funding requirements resulting from such earnings deficiency will be recovered in customer rates.
Ameren Missouri has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway energy center.Energy Center. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 20172019 and 2016.2018. Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities.
The following table presents proceeds from the sale and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2017, 2016,2019, 2018, and 2015:2017:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Proceeds from sales and maturities | $ | 260 |
| | $ | 299 |
| | $ | 305 |
|
| Gross realized gains | 10 |
| | 18 |
| | 13 |
|
| Gross realized losses | 2 |
| | 5 |
| | 5 |
|
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Proceeds from sales and maturities | $ | 396 |
| | $ | 377 |
| | $ | 349 |
|
| Gross realized gains | 13 |
| | 7 |
| | 8 |
|
| Gross realized losses | 5 |
| | 4 |
| | 2 |
|
Net realized and unrealized gains and losses are deferred and are currently reflected in the regulatory liability related to AROs on Ameren’s and Ameren Missouri’s balance sheets. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by Ameren Missouri’s customers. See Note 2 – Rate and Regulatory Matters.Matters for the regulatory liability recorded at December 31, 2019.
The following table presents the costscost and fair valuesvalue of investments in debt and equity securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund at December 31, 20172019 and 20162018:
|
| | | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2019 | | | | | | | |
| Debt securities | $ | 262 |
| | $ | 11 |
| | $ | — |
| | $ | 273 |
|
| Equity securities | 183 |
| | 393 |
| | 7 |
| | 569 |
|
| Cash and cash equivalents | 26 |
| | — |
| | — |
| | 26 |
|
Other(a) | (21 | ) | | — |
| | — |
| | (21 | ) |
| Total | $ | 450 |
| | $ | 404 |
| | $ | 7 |
| | $ | 847 |
|
| 2018 | | | | | | | |
| Debt securities | $ | 253 |
| | $ | 3 |
| | $ | 4 |
| | $ | 252 |
|
| Equity securities | 162 |
| | 277 |
| | 12 |
| | 427 |
|
| Cash and cash equivalents | 3 |
| | — |
| | — |
| | 3 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 420 |
| | $ | 280 |
| | $ | 16 |
| | $ | 684 |
|
|
| | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2017 | | | | | | | |
| Debt securities | $ | 228 |
| | $ | 5 |
| $ | 1 |
| | $ | 232 |
|
| Equity securities | 155 |
| | 318 |
| | 5 |
| | 468 |
|
| Cash and cash equivalents | 2 |
| | — |
| | — |
| | 2 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 387 |
| | $ | 323 |
| $ | 6 |
| | $ | 704 |
|
| 2016 | | | | | | | |
| Debt securities | $ | 197 |
| | $ | 3 |
| $ | 4 |
| | $ | 196 |
|
| Equity securities | 161 |
| | 253 |
| | 6 |
| | 408 |
|
| Cash and cash equivalents | 1 |
| | — |
| | — |
| | 1 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 361 |
| | $ | 256 |
| $ | 10 |
| | $ | 607 |
|
| |
| (a) | Represents net receivables and payables relating to pending securitysecurities sales, interest, and securitysecurities purchases. |
The following table presents the costs and fair values of investments in debt securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 20172019:
|
| | | | | | | |
| | Cost | | Fair Value |
| Less than 5 years | $ | 112 |
| | $ | 114 |
|
| 5 years to 10 years | 56 |
| | 58 |
|
| Due after 10 years | 94 |
| | 101 |
|
| Total | $ | 262 |
| | $ | 273 |
|
|
| | | | | | | |
| | Cost | | Fair Value |
| Less than 5 years | $ | 120 |
| | $ | 120 |
|
| 5 years to 10 years | 54 |
| | 55 |
|
| Due after 10 years | 54 |
| | 57 |
|
| Total | $ | 228 |
| | $ | 232 |
|
There are unrealized losses relating to certain available-for-sale investments included in the nuclear decommissioning trust fund, deferred within the regulatory liability as discussed above. Decommissioning will not occur until Ameren Missouri’s nuclear energy centerthe Callaway Energy Center is retired. The Callaway energy center’s operating license expires in 2044.
Insurance
The following table presents insurance coverage at Ameren Missouri’s Callaway energy centerEnergy Center at December 31, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year.2019:
|
| | | | | | | | | |
| Type and Source of Coverage | Most Recent Renewal Date | Maximum Coverages | | Maximum Assessments for Single Incidents | |
| Public liability and nuclear worker liability: | | | | | |
| American Nuclear Insurers | January 1, 2020 | $ | 450 |
| | $ | — |
| |
| Pool participation | (a) | 13,486 |
| (a) | 138 |
| (b) |
| | | $ | 13,936 |
| (c) | $ | 138 |
| |
| Property damage: | | | | | |
| NEIL and EMANI | April 1, 2019 | $ | 3,200 |
| (d) | $ | 27 |
| (e) |
| Replacement power: | | | | | |
| NEIL | April 1, 2019 | $ | 490 |
| (f) | $ | 7 |
| (e) |
|
| | | | | | | | |
| Type and Source of Coverage | Maximum Coverages | | Maximum Assessments for Single Incidents | |
| Public liability and nuclear worker liability: | | | | |
| American Nuclear Insurers | $ | 450 |
| | $ | — |
| |
| Pool participation | 12,986 |
| (a) | 127 |
| (b) |
| | $ | 13,436 |
| (c) | $ | 127 |
| |
| Property damage: | | | | |
| NEIL and EMANI | $ | 3,200 |
| (d) | $ | 30 |
| (e) |
| Replacement power: | | | | |
| NEIL | $ | 490 |
| (f) | $ | 7 |
| (e) |
| |
| (a) | Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program. |
| |
| (b) | Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $19$21 million per year. |
| |
| (c) | Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors. |
| |
| (d) | NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events. |
| |
| (e) | All NEIL insuredNEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL. |
| |
| (f) | Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million. |
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. 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. The most recent five-year inflationary adjustment became effective in September 2013.November 2018. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates. Terroristaggregates, such that terrorist acts against one or more commercial nuclear power plants insured by NEIL or EMANI within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share one fullthe limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination.contamination, resulting from terrorist attacks. The EMANI policies have an aggregate limitare not subject to industrywide aggregates in the event of €600 million for radiation and nonradiation events within a period of 72 hours.terrorist attacks on nuclear facilities.
If losses from a nuclear incident at the Callaway energy centerEnergy Center exceed the insurance limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.
NOTE 10 – RETIREMENT BENEFITS
The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren has defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren has defined benefit pension plans covering substantially all of its non-union employees and postretirement benefit plans covering non-union employees hired before October 2015.2015 and union employees hired before January 2020. Ameren uses a measurement date of December 31
for its pension and postretirement benefit plans. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. Ameren’s qualified pension plan is the
Ameren Retirement Plan. Ameren also has an unfunded nonqualified pension plan, the Ameren Supplemental Retirement Plan, which is available to provide certain management employees and retirees with a supplemental benefit when their qualified pension plan benefits are capped in compliance with Internal Revenue Code limitations. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Effective December 31, 2016, the applicable assets and liabilities of the Ameren Group Life Insurance Plan were merged with the Ameren Retiree Welfare Benefit Plan. Only Ameren subsidiaries participate in the plans listed above.
Ameren’s unfunded obligation under its pension and other postretirement benefit plans was $551$216 million and $774$481 million as of December 31, 20172019 and 2016,2018, respectively. These net liabilities are recorded in “Other current liabilities” andliabilities,” “Pension and other postretirement benefits”benefits,” and “Other assets” on Ameren’s consolidated balance sheet. The decrease in the unfunded obligation during 20172019 was primarily the result of a larger-than-expectedan increase in the return on plan assets of the pension and postretirement trusts offset by a 5075 basis point decrease in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligation. The decrease in the unfunded obligation also resulted in a decrease to “Regulatory assets” on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets.
The following table presents the net benefit liabilityliability/(asset) recorded on the balance sheets of each of the Ameren Companies as of December 31, 20172019 and 20162018:
|
| | | | | | |
| | 2019 |
| 2018 |
|
Ameren(a) | $ | 216 |
| $ | 481 |
|
| Ameren Missouri | 142 |
| 229 |
|
Ameren Illinois(a) | (16 | ) | 120 |
|
|
| | | | | | |
| | 2017 |
| 2016 |
|
Ameren(a) | $ | 551 |
| $ | 774 |
|
| Ameren Missouri | 215 |
| 293 |
|
Ameren Illinois(b) | 213 |
| 315 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(b) | OtherAssets associated with other postretirement benefit liability isbenefits are recorded in “Other assets” on the balance sheet. |
Ameren recognizes the underfunded status of its pension and postretirement plans as a liability on its consolidated balance sheet, with offsetting entries to accumulated OCI and regulatory assets. The following table presents the funded status of Ameren’s pension and postretirement benefit plans as of December 31, 20172019 and 20162018. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 20172019 and 20162018, that have not been recognized in net periodic benefit costs.
|
| | | | | | | | | | | | | |
| | 2019 | | 2018 |
| | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
| Accumulated benefit obligation at end of year | $ | 4,735 |
| $ | (a) |
| | $ | 4,258 |
| $ | (a) |
|
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,459 |
| $ | 1,034 |
| | $ | 4,827 |
| $ | 1,240 |
|
| Service cost | 88 |
| | 18 |
| | 100 |
| | 21 |
|
| Interest cost | 187 |
| | 43 |
| | 169 |
| | 40 |
|
| Plan amendments | — |
| | 2 |
| | — |
| | (49 | ) |
| Participant contributions | — |
| | 8 |
| | — |
| | 9 |
|
| Actuarial (gain) loss | 469 |
| | 69 |
| | (401 | ) | | (163 | ) |
| Benefits paid | (236 | ) | | (64 | ) | | (236 | ) | | (64 | ) |
| Net benefit obligation at end of year | 4,967 |
| | 1,110 |
| | 4,459 |
| | 1,034 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 3,899 |
| | 1,113 |
| | 4,293 |
| | 1,223 |
|
| Actual return on plan assets | 878 |
| | 237 |
| | (218 | ) | | (57 | ) |
| Employer contributions | 23 |
| | 3 |
| | 60 |
| | 2 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 9 |
|
| Benefits paid | (236 | ) | | (64 | ) | | (236 | ) | | (64 | ) |
| Fair value of plan assets at end of year | 4,564 |
| | 1,297 |
| | 3,899 |
| | 1,113 |
|
| Funded status – deficiency (surplus) | 403 |
| | (187 | ) | | 560 |
| | (79 | ) |
| Accrued benefit cost (asset) at December 31 | $ | 403 |
| $ | (187 | ) | | $ | 560 |
| $ | (79 | ) |
| Amounts recognized in the balance sheet consist of: | | | | | | | |
Noncurrent asset(b) | $ | — |
| $ | (187 | ) | | $ | — |
| $ | (79 | ) |
Current liability(c) | 2 |
| | — |
| | 2 |
| | — |
|
| Noncurrent liability | 401 |
| | — |
| | 558 |
| | — |
|
| Net liability (asset) recognized | $ | 403 |
| $ | (187 | ) | | $ | 560 |
| $ | (79 | ) |
| Amounts recognized in regulatory assets consist of: | | | | | | | |
| Net actuarial (gain) loss | $ | 244 |
| $ | (170 | ) | | $ | 393 |
| $ | (91 | ) |
| Prior service credit | — |
| | (41 | ) | | (2 | ) | | (48 | ) |
| Amounts recognized in accumulated OCI (pretax) consist of: | | | | | | | |
| Net actuarial loss | 26 |
| | 4 |
| | 35 |
| | 3 |
|
| Total | $ | 270 |
| $ | (207 | ) | | $ | 426 |
| $ | (136 | ) |
|
| | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Pension Benefits(a) | | Postretirement Benefits(a) | | Pension Benefits(a) | | Postretirement Benefits(a) |
| Accumulated benefit obligation at end of year | $ | 4,577 |
| $ | (b) |
| | $ | 4,288 |
| $ | (b) |
|
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,518 |
| $ | 1,170 |
| | $ | 4,197 |
| $ | 1,094 |
|
| Service cost | 93 |
| | 21 |
| | 81 |
| | 19 |
|
| Interest cost | 179 |
| | 47 |
| | 185 |
| | 50 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 8 |
|
| Actuarial loss | 255 |
| | 53 |
| | 265 |
| | 52 |
|
| Benefits paid | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Federal subsidy on benefits paid | (b) |
| | — |
| | (b) |
| | 1 |
|
| Net benefit obligation at end of year | 4,827 |
| | 1,240 |
| | 4,518 |
| | 1,170 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 3,813 |
| | 1,101 |
| | 3,653 |
| | 1,071 |
|
| Actual return on plan assets | 634 |
| | 171 |
| | 313 |
| | 73 |
|
| Employer contributions | 64 |
| | 2 |
| | 57 |
| | 2 |
|
| Federal subsidy on benefits paid | (b) |
| | — |
| | (b) |
| | 1 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 8 |
|
| Benefits paid | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Fair value of plan assets at end of year | 4,293 |
| | 1,223 |
| | 3,813 |
| | 1,101 |
|
| Funded status – deficiency | 534 |
| | 17 |
| | 705 |
| | 69 |
|
| Accrued benefit cost at December 31 | $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in the balance sheet consist of: | | | | | | | |
Current liability(c) | 3 |
| | 3 |
| | 3 |
| | 2 |
|
| Noncurrent liability | 531 |
| | 14 |
| | 702 |
| | 67 |
|
| Net liability recognized | $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in regulatory assets consist of: | | | | | | | |
| Net actuarial (gain) loss | $ | 374 |
| $ | (69 | ) | | $ | 535 |
| $ | (29 | ) |
| Prior service credit | (3 | ) | | (3 | ) | | (4 | ) | | (8 | ) |
| Amounts (pretax) recognized in accumulated OCI consist of: | | | | | | | |
| Net actuarial loss | 30 |
| | 2 |
| | 43 |
| | — |
|
| Prior service credit | — |
| | — |
| | — |
| | (1 | ) |
| Total | $ | 401 |
| $ | (70 | ) | | $ | 574 |
| $ | (38 | ) |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries.Not applicable. |
| |
| (b) | Not applicable.Included in “Other assets” on Ameren’s consolidated balance sheet. |
| |
| (c) | Included in “Other current liabilities” on Ameren’s consolidated balance sheet. |
The following table presents the assumptions used to determine our benefit obligations at December 31, 20172019 and 20162018:
|
| | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Discount rate at measurement date | 3.50 | % | | 4.25 | % | | 3.50 | % | | 4.25 | % |
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial)(a) | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate)(a) | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
|
| | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Discount rate at measurement date | 3.50 | % | | 4.00 | % | | 3.50 | % | | 4.00 | % |
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial)(a) | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate)(a) | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
| |
| (a) | Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%. |
Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan’s projected benefit payments. The settlement portfolio of bonds is selected from a pool of more than 600nearly 900 high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan’s benefit payments that equates to the market value of the selected bonds. In addition, during 2017,2019, Ameren adopted the Society of Actuaries 2017mortality table and adopted the
Society of Actuaries 2019 Mortality Improvement Scale. The updated mortality table reflects lower life expectancy in aggregate compared with the 2018 Society of Actuaries mortality table. The updated improvement scale assumes a lower rate of mortality improvement, as compared towith the 20162018 Mortality Improvement Scale that Ameren
used in 2016, resultingScale. The impact of the adoption of the table and the scale results in a decrease to our pension and other postretirement benefit obligations.
Funding
Pension benefits are based on the employees’ years of service, age, and compensation. Ameren’s pension plans are funded in compliance with income tax regulations, federal funding, and other regulatory requirements. As a result, Ameren expects to fund its pension plan at a level equal to the greater of the pension cost or the legally required minimum contribution. ConsideringBased on its assumptions at December 31, 20172019, its investment performance in 2017,2019, and its pension funding policy, Ameren expects to make annual contributions of less than $1 millionup to approximately $6045 million in each of the next five years, with aggregate estimated contributions of $12070 million. Ameren Missouri and Ameren Illinois expectestimate that their portion of the future funding requirements towill be 35%30% and 55%60%, respectively. These amounts are estimates. Theyestimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the cash contributions made to our defined benefit retirement plan and to our postretirement plans during 20172019, 20162018, and 20152017:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Ameren Missouri | $ | 19 |
| | $ | 21 |
| | $ | 47 |
| | $ | 1 |
| | $ | 1 |
| | $ | 8 |
| $ | 3 |
| | $ | 18 |
| | $ | 19 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Ameren Illinois | 37 |
| | 30 |
| | 45 |
| | 1 |
| | 1 |
| | 8 |
| 19 |
| | 35 |
| | 37 |
| | 1 |
| | 1 |
| | 1 |
|
| Other | 8 |
| | 6 |
| | 19 |
| | — |
| | — |
| | 2 |
| 1 |
| | 7 |
| | 8 |
| | 1 |
| | — |
| | — |
|
| Ameren | 64 |
| | 57 |
| | 111 |
| | 2 |
| | 2 |
| | 18 |
| $ | 23 |
| | $ | 60 |
| | $ | 64 |
| | $ | 3 |
| | $ | 2 |
| | $ | 2 |
|
Investment Strategy and Policies
Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, which includes members of senior management, approves and implements investment strategy and asset allocation guidelines for the plan assets. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable; and second, to maximize total return on plan assets and to minimize expense volatility consistent with its tolerance for risk. Ameren delegates the task of investment management to specialists in each asset class. As appropriate, Ameren provides each investment manager with guidelines that specify allowable and prohibited investment types. The investment committee regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. Ameren will use an expected return on plan assets for its pension and postretirement plan assets of 7.00% in 2018.2020. No plan assets are expected to be returned to Ameren during 2018.2020.
Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration, market capitalization, country, style (growth or value), and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk. The following table presents our target allocations for 20182020 and our pension and postretirement plans’ asset categories as of December 31, 20172019 and 20162018:
|
| | | | | | | |
Asset Category | Target Allocation 2020 | | Percentage of Plan Assets at December 31, |
| 2019 | | 2018 |
| Pension Plan: | | | | | |
| Cash and cash equivalents | 0% – 5% | | 3 | % | | 1 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 21% – 31% | | 27 | % | | 24 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 7 | % | | 7 | % |
| International | 9% – 19% | | 14 | % | | 13 | % |
| Global | 3% – 13% | | 9 | % | | 8 | % |
| Total equity | 51% – 61% | | 57 | % | | 52 | % |
| Debt securities | 35% – 45% | | 36 | % | | 42 | % |
| Real estate | 0% – 9% | | 4 | % | | 5 | % |
| Private equity | 0% – 5% | | (a) |
| | (a) |
|
| Total | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | |
| Cash and cash equivalents | 0% – 7% | | 1 | % | | 2 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 23% – 33% | | 31 | % | | 40 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 7 | % |
| International | 9% – 19% | | 14 | % | | 13 | % |
| Global | 5% – 15% | | 11 | % | | — | % |
| Total equity | 55% – 65% | | 65 | % | | 60 | % |
| Debt securities | 33% – 43% | | 34 | % | | 38 | % |
| Total | | | 100 | % | | 100 | % |
|
| | | | | | | |
Asset Category | Target Allocation 2018 | | Percentage of Plan Assets at December 31, |
| 2017 | | 2016 |
| Pension Plan: | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 1 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 29% – 39% | | 34 | % | | 34 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 9 | % |
| International and emerging markets | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 51% – 61% | | 57 | % | | 57 | % |
| Debt securities | 35% – 45% | | 37 | % | | 37 | % |
| Real estate | 0% – 9% | | 5 | % | | 5 | % |
| Private equity | 0% – 5% | | (a) |
| | (a) |
|
| Total | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | |
| Cash and cash equivalents | 0% – 7% | | 2 | % | | 3 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 34% – 44% | | 41 | % | | 40 | % |
| U.S. small- and mid-capitalization | 2% – 12% | | 8 | % | | 7 | % |
| International and emerging markets | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 55% – 65% | | 63 | % | | 61 | % |
| Debt securities | 33% – 43% | | 35 | % | | 36 | % |
| Total | | | 100 | % | | 100 | % |
| |
(a) | Less than 1% of plan assets. |
In general, the United States large-capitalization equity investments are passively managed or indexed, whereas the international, emerging markets,global, United States small-capitalization, and United States mid-capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed-income vehicles. Debt security investments in high-yield securities, emerging market securities and non-United-States-dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. Additionally, Ameren’s investment committee allows investment managers to use derivatives, such as index futures, foreign exchange futures, and options, in certain situations to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 20172019. The fair value of an asset is the amount that would be received upon its sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the measurement date or, if that is not a business day, on the last business day before that date. Securities traded in over-the-counter markets are valued by quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Investments measured under NAV as a practical expedient are based on the fair values of the underlying assets provided by the funds and their administrators. The fair value of real estate investments is based on NAV; it is determined by annual appraisal reports prepared by an independent real estate appraiser. Investments measured at NAV often provide for daily, monthly, or quarterly redemptions with 60 or less days of notice depending on the fund. For some funds, redemption may also require approval from the fund’s board of directors. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pension plans’ assets measured at fair value and NAV as of December 31, 2017:2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | | December 31, 2018 |
| | Level 1 | | Level 2 | | NAV | | Total | | | Level 1 | | Level 2 | | NAV | | Total |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 139 |
| | $ | 139 |
| | | $ | — |
| | $ | — |
| | $ | 41 |
| | $ | 41 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | 1,253 |
| | 1,253 |
| | | — |
| | — |
| | 955 |
| | 955 |
|
| U.S. small- and mid-capitalization | 344 |
| | — |
| | — |
| | 344 |
| | | 272 |
| | — |
| | — |
| | 272 |
|
| International | 296 |
| | — |
| | 363 |
| | 659 |
| | | 224 |
| | — |
| | 298 |
| | 522 |
|
| Global | — |
| | — |
| | 407 |
| | 407 |
| | | — |
| | — |
| | 321 |
| | 321 |
|
| Debt securities: | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 597 |
| | 13 |
| | 610 |
| | | — |
| | 701 |
| | 19 |
| | 720 |
|
| Municipal bonds | — |
| | 75 |
| | — |
| | 75 |
| | | — |
| | 87 |
| | — |
| | 87 |
|
| U.S. Treasury and agency securities | 5 |
| | 1,010 |
| | — |
| | 1,015 |
| | | — |
| | 891 |
| | — |
| | 891 |
|
| Other | — |
| | 8 |
| | — |
| | 8 |
| | | 1 |
| | 11 |
| | — |
| | 12 |
|
| Real estate | — |
| | — |
| | 211 |
| | 211 |
| | | — |
| | — |
| | 202 |
| | 202 |
|
| Private equity | — |
| | — |
| | 2 |
| | 2 |
| | | — |
| | — |
| | 3 |
| | 3 |
|
| Total | $ | 645 |
| | $ | 1,690 |
| | $ | 2,388 |
| | $ | 4,723 |
| | | $ | 497 |
| | $ | 1,690 |
| | $ | 1,839 |
| | $ | 4,026 |
|
Less: Medical benefit assets(a) | | | | | | | (176 | ) | | | | | | | | | (144 | ) |
Plus: Net receivables(b) | | | | | | | 17 |
| | | | | | | | | 17 |
|
| Fair value of pension plans’ assets | | | | | | | $ | 4,564 |
| | | | | | | | | $ | 3,899 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | 25 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,523 |
| | 1,523 |
|
| U.S. small- and mid-capitalization | 379 |
| | — |
| | — |
| | — |
| | 379 |
|
| International and emerging markets | 179 |
| | — |
| | — |
| | 450 |
| | 629 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 726 |
| | — |
| | 15 |
| | 741 |
|
| Municipal bonds | — |
| | 91 |
| | — |
| | — |
| | 91 |
|
| U.S. Treasury and agency securities | 8 |
| | 816 |
| | — |
| | — |
| | 824 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Real estate | — |
| | — |
| | — |
| | 196 |
| | 196 |
|
| Private equity | — |
| | — |
| | — |
| | 4 |
| | 4 |
|
| Total | $ | 566 |
| | $ | 1,640 |
| | $ | — |
| | $ | 2,213 |
| | $ | 4,419 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | | | (153 | ) |
Plus: Net receivables at December 31(b) | | | | | | | | | 27 |
|
| Fair value of pension plans’ assets at December 31 | | | | | | | | | $ | 4,293 |
|
| |
| (a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. |
| |
| (b) | Receivables related to pending securitysecurities sales, offset by payables related to pending securitysecurities purchases. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pensionpostretirement benefit plans’ assets measured at fair value and NAV as of December 31, 2016:2019 and 2018:
| | | | | | | | | | | | | | December 31, 2019 | | | December 31, 2018 |
| | Quoted Prices in Active Markets for Identified Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total | Level 1 | | Level 2 | | NAV | | Total | | | Level 1 | | Level 2 | | NAV | | Total |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
| $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 12 |
| | | $ | 32 |
| | $ | — |
| | $ | — |
| | $ | 32 |
|
| Equity securities: | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,352 |
| | 1,352 |
| 238 |
| | — |
| | 112 |
| | 350 |
| | | 297 |
| | — |
| | 89 |
| | 386 |
|
| U.S. small- and mid-capitalization | 361 |
| | — |
| | — |
| | — |
| | 361 |
| 93 |
| | — |
| | — |
| | 93 |
| �� | | 63 |
| | — |
| | — |
| | 63 |
|
| International and emerging markets | 133 |
| | — |
| | — |
| | 389 |
| | 522 |
| |
| International | | 59 |
| | — |
| | 102 |
| | 161 |
| | | 45 |
| | — |
| | 84 |
| | 129 |
|
| Global | | — |
| | — |
| | 120 |
| | 120 |
| | | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | — |
| | — |
| | — |
| | | — |
| | 12 |
| | — |
| | 12 |
|
| Debt securities: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 617 |
| | — |
| | 13 |
| | 630 |
| — |
| | — |
| | — |
| | — |
| | | — |
| | 144 |
| | — |
| | 144 |
|
| Municipal bonds | — |
| | 95 |
| | — |
| | — |
| | 95 |
| — |
| | 107 |
| | — |
| | 107 |
| | | — |
| | 107 |
| | — |
| | 107 |
|
| U.S. Treasury and agency securities | — |
| | 701 |
| | — |
| | — |
| | 701 |
| — |
| | — |
| | — |
| | — |
| | | — |
| | 62 |
| | — |
| | 62 |
|
| Other | — |
| | 21 |
| | — |
| | — |
| | 21 |
| — |
|
| — |
| | 277 |
| | 277 |
| | | — |
| | 7 |
| | 34 |
| | 41 |
|
| Real estate | — |
| | — |
| | — |
| | 202 |
| | 202 |
| |
| Private equity | — |
| | — |
| | — |
| | 6 |
| | 6 |
| |
| Total | $ | 494 |
| | $ | 1,434 |
| | $ | — |
| | $ | 1,995 |
| | $ | 3,923 |
| $ | 402 |
|
| $ | 107 |
| | $ | 611 |
| | $ | 1,120 |
| | | $ | 437 |
| | $ | 332 |
| | $ | 207 |
| | $ | 976 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | | | (132 | ) | |
Plus: Net receivables at December 31(b) | | | | | | | | | 22 |
| |
| Fair value of pension plans’ assets at December 31 | | �� | | | | | | | $ | 3,813 |
| |
Plus: Medical benefit assets(a) | | | | | | | | 176 |
| | | | | | | | | 144 |
|
Less: Net payables(b) | | | | | | | | 1 |
| | | | | | | | | (7 | ) |
| Fair value of postretirement benefit plans’ assets | | | | | | | | $ | 1,297 |
| | | | | | | | | $ | 1,113 |
|
| |
| (a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. |
| |
(b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans’ assets measured at fair value as of December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | 44 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 44 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | 332 |
| | — |
| | — |
| | 110 |
| | 442 |
|
| U.S. small- and mid-capitalization | 80 |
| | — |
| | — |
| | — |
| | 80 |
|
| International and emerging markets | 53 |
| | — |
| | — |
| | 101 |
| | 154 |
|
| Other | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 144 |
| | — |
| | — |
| | 144 |
|
| Municipal bonds | — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 76 |
| | — |
| | — |
| | 76 |
|
| Other | — |
| | 4 |
| | — |
| | 34 |
| | 38 |
|
| Total | $ | 509 |
| | $ | 342 |
| | $ | — |
| | $ | 245 |
| | $ | 1,096 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | | | 153 |
|
Less: Net payables at December 31(b) | | | | | | | | | (26 | ) |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | $ | 1,223 |
|
| |
(a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
| (b) | Payables related to pending securitysecurities purchases, offset by interest receivables and receivables related to pending security sales. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans’ assets measured at fair value as of December 31, 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | 53 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | 291 |
| | — |
| | — |
| | 101 |
| | 392 |
|
| U.S. small- and mid-capitalization | 72 |
| | — |
| | — |
| | — |
| | 72 |
|
| International and emerging markets | 40 |
| | — |
| | — |
| | 92 |
| | 132 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 141 |
| | — |
| | — |
| | 141 |
|
| Municipal bonds | — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 68 |
| | — |
| | — |
| | 68 |
|
| Other | — |
| | — |
| | — |
| | 19 |
| | 19 |
|
| Total | $ | 456 |
| | $ | 326 |
| | $ | — |
| | $ | 212 |
| | $ | 994 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | | | 132 |
|
Less: Net payables at December 31(b) | | | | | | | | | (25 | ) |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | $ | 1,101 |
|
| |
(a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
(b) | Payables related to pending security purchases, offset by interest receivables and receivables related to pending securitysecurities sales. |
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of Ameren’s pension and postretirement benefit plans during 20172019, 20162018, and 20152017:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | | Postretirement Benefits |
| 2017 | | | | |
| Service cost | $ | 93 |
| | $ | 21 |
| |
| | | 2019 | | 2018 | | 2017 | | | 2019 | | 2018 | | 2017 |
Service cost(a) | | $ | 88 |
| | $ | 100 |
| | $ | 93 |
| | | $ | 18 |
| | $ | 21 |
| | $ | 21 |
|
| Non-service cost components: | | | | | | | | | | | | | |
| Interest cost | 179 |
| | 47 |
| 187 |
| | 169 |
| | 179 |
| | | 43 |
| | 40 |
| | 47 |
|
| Expected return on plan assets | (262 | ) | | (75 | ) | (276 | ) | | (276 | ) | | (262 | ) | | | (77 | ) | | (77 | ) | | (75 | ) |
| Amortization of: | | | | | | | | | | | | | | | |
| Prior service credit | (1 | ) | | (5 | ) | (1 | ) | | (1 | ) | | (1 | ) | | | (5 | ) | | (4 | ) | | (5 | ) |
| Actuarial (gain) loss | 55 |
| | (6 | ) | 25 |
| | 68 |
| | 55 |
| | | (15 | ) | | (6 | ) | | (6 | ) |
Total non-service cost components(b) | | $ | (65 | ) | | $ | (40 | ) | | $ | 29 |
| | | $ | (54 | ) | | $ | (47 | ) | | $ | (39 | ) |
| Net periodic benefit cost (income) | $ | 64 |
| | $ | (18 | ) | $ | 23 |
| | $ | 60 |
| | $ | 64 |
| | | $ | (36 | ) | | $ | (26 | ) | | $ | (18 | ) |
| 2016 | | | | |
| Service cost | $ | 81 |
| | $ | 19 |
| |
| Interest cost | 185 |
| | 50 |
| |
| Expected return on plan assets | (253 | ) | | (72 | ) | |
| Amortization of: | | | | |
| Prior service credit | (1 | ) | | (5 | ) | |
| Actuarial (gain) loss | 32 |
| | (11 | ) | |
| Net periodic benefit cost (income) | $ | 44 |
| | $ | (19 | ) | |
| 2015 | | | | |
| Service cost | $ | 92 |
| | $ | 24 |
| |
| Interest cost | 174 |
| | 48 |
| |
| Expected return on plan assets | (248 | ) | | (68 | ) | |
| Amortization of: | | | | |
| Prior service credit | (1 | ) | | (5 | ) | |
| Actuarial loss | 74 |
| | 5 |
| |
| Curtailment gain | 1 |
| | — |
| |
| Net periodic benefit cost | $ | 92 |
| | $ | 4 |
| |
(a) Service cost, net of capitalization, is reflected in “Operating Expenses - Other operations and maintenance” on Ameren’s statement of income.
| |
| (b) | 2019 and 2018 amounts and the non-capitalized portion of 2017 non-service cost components are reflected in “Other Income, Net” on Ameren’s consolidated statement of income. See Note 6 – Other Income, Net for additional information. |
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into Ameren’s net periodic benefit cost in 20182020 are as follows:
| | | Pension Benefits(a) | | Postretirement Benefits(a) | Pension Benefits | | Postretirement Benefits |
| Regulatory assets: | | | | | | |
| Prior service credit | $ | (1 | ) | | $ | (2 | ) | $ | (1 | ) | | $ | (4 | ) |
| Net actuarial (gain) loss | 60 |
| | (1 | ) | 52 |
| | (9 | ) |
| Accumulated OCI: | | | | | | |
| Net actuarial loss | 5 |
| | — |
| 5 |
| | — |
|
| Total | $ | 64 |
| | $ | (3 | ) | $ | 56 |
| | $ | (13 | ) |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. Net actuarial gains or losses subject to amortization are amortized on a straight-line basis over 10 years.
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 20172019, 20162018, and 20152017:
| | | | Pension Costs | | Postretirement Costs | Pension Costs | | Postretirement Costs |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
Ameren Missouri(a) | $ | 24 |
| | $ | 26 |
| | $ | 54 |
| | $ | (4 | ) | | $ | (5 | ) | | $ | 8 |
| $ | 5 |
| | $ | 22 |
| | $ | 24 |
| | $ | (6 | ) | | $ | (1 | ) | | $ | (4 | ) |
| Ameren Illinois | 41 |
| | 22 |
| | 38 |
| | (14 | ) | | (13 | ) | | (3 | ) | 20 |
| | 39 |
| | 41 |
| | (30 | ) | | (25 | ) | | (14 | ) |
| Other | (1 | ) | | (4 | ) | | — |
| | — |
| | (1 | ) | | (1 | ) | (2 | ) | | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
|
| Ameren | 64 |
| | 44 |
| | 92 |
| | (18 | ) | | (19 | ) | | 4 |
| $ | 23 |
| | $ | 60 |
| | $ | 64 |
| | (36 | ) | | $ | (26 | ) | | $ | (18 | ) |
| |
| (a) | Does not include the impact of the regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. |
The expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, as of December 31, 20172019, are as follows:
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Paid from Qualified Trust Funds | | Paid from Company Funds | | Paid from Qualified Trust Funds | | Paid from Company Funds |
| 2020 | $ | 257 |
| | $ | 3 |
| | $ | 58 |
| | $ | 2 |
|
| 2021 | 269 |
| | 3 |
| | 60 |
| | 2 |
|
| 2022 | 274 |
| | 3 |
| | 61 |
| | 2 |
|
| 2023 | 279 |
| | 3 |
| | 63 |
| | 2 |
|
| 2024 | 284 |
| | 3 |
| | 64 |
| | 2 |
|
2025 – 2029 | 1,446 |
| | 12 |
| | 313 |
| | 12 |
|
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Paid from Qualified Trust Funds | | Paid from Company Funds | | Paid from Qualified Trust Funds | | Paid from Company Funds |
| 2018 | $ | 255 |
| | $ | 3 |
| | $ | 57 |
| | $ | 2 |
|
| 2019 | 261 |
| | 3 |
| | 59 |
| | 2 |
|
| 2020 | 266 |
| | 3 |
| | 62 |
| | 2 |
|
| 2021 | 277 |
| | 3 |
| | 64 |
| | 2 |
|
| 2022 | 280 |
| | 3 |
| | 65 |
| | 2 |
|
2023 – 2027 | 1,421 |
| | 13 |
| | 331 |
| | 12 |
|
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 20172019, 20162018, and 20152017:
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Discount rate at measurement date | 4.25 | % | | 3.50 | % | | 4.00 | % | | 4.25 | % | | 3.50 | % | | 4.00 | % |
| Expected return on plan assets | 7.00 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
|
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial)(a) | (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate)(a) | (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount rate at measurement date | 4.00 | % | | 4.50 | % | | 4.00 | % | | 4.00 | % | | 4.50 | % | | 4.00 | % |
| Expected return on plan assets | 7.00 |
| | 7.00 |
| | 7.25 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
|
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial)(a) | (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate)(a) | (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
| |
| (a) | Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%. |
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Service Cost and Interest Cost | | Expected Return on Assets | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Expected Return on Assets | | Postretirement Benefit Obligation |
| 0.25% decrease in discount rate | $ | (1 | ) | | $ | — |
| | $ | 165 |
| | $ | — |
| | $ | — |
| | $ | 36 |
|
| 0.25% decrease in return on assets | — |
| | 10 |
| | — |
| | — |
| | 3 |
| | — |
|
| 0.25% increase in future compensation | 2 |
| | — |
| | 14 |
| | — |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | — |
| | 3 |
| | — |
| | 57 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | — |
| | (3 | ) | | — |
| | (57 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Service Cost and Interest Cost | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Postretirement Benefit Obligation |
| 0.25% decrease in discount rate | $ | (1 | ) | | $ | 157 |
| | $ | — |
| | $ | 44 |
|
| 0.25% increase in salary scale | 2 |
| | 15 |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | 4 |
| | 71 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | (4 | ) | | (71 | ) |
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible Ameren employees at December 31, 20172019. The plan allows employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matches a percentage of the employee contributions up to certain limits. The following table presents the portion of the matching contribution to the Ameren 401(k) plan attributable to the continuing operations for each of the Ameren Companies for the years ended December 31, 20172019, 20162018, and 20152017:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Ameren Missouri | $ | 19 |
| | $ | 17 |
| | $ | 16 |
|
| Ameren Illinois | 16 |
| | 15 |
| | 13 |
|
| Other | — |
| | 1 |
| | 1 |
|
| Ameren | $ | 35 |
| | $ | 33 |
| | $ | 30 |
|
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 16 |
| | $ | 16 |
| | $ | 16 |
|
| Ameren Illinois | 13 |
| | 12 |
| | 12 |
|
| Other | 1 |
| | 1 |
| | 1 |
|
| Ameren | 30 |
| | 29 |
| | 29 |
|
NOTE 11 – STOCK-BASED COMPENSATION
The 2014 Omnibus Incentive Compensation Plan is Ameren’s long-term stockstock-based compensation plan for eligible employees and directors. The 2014 Incentive PlanIt provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors. At December 31, 2017,2019, there were 4.93.1 million common shares remaining for grant under the 2014 Incentive Plan. The 2014 Incentive Plan awardsgrant. Awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2019 and 2018, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2020.
The following table summarizes Ameren’s nonvested performance share unit and restricted stock unit activity for the year ended December 31, 2019:
|
| | | | | | | | | | | | | |
| | Performance Share Units | | Restricted Stock Units |
| | Share Units | | Weighted-average Fair Value per Share Unit | | Stock Units | | Weighted-average Fair Value per Stock Unit |
Nonvested at January 1, 2019(a) | 682,811 |
| | $ | 56.58 |
| | 155,253 |
| | $ | 57.38 |
|
| Granted | 304,384 |
| | 67.42 |
| | 132,526 |
| | 65.89 |
|
| Forfeitures | (35,120 | ) | | 64.40 |
| | (11,802 | ) | | 62.75 |
|
Vested and undistributed(b) | (235,275 | ) | | 62.28 |
| | (53,297 | ) | | 61.99 |
|
| Vested and distributed | (176,923 | ) | | 44.13 |
| | (2,403 | ) | | 54.30 |
|
Nonvested at December 31, 2019(c) | 539,877 |
| | $ | 63.79 |
| | 220,277 |
| | $ | 61.13 |
|
| |
| (a) | Does not include 619,783 performance share units and 26,557 restricted stock units that were vested and undistributed. |
| |
| (b) | Vested and undistributed units are awards that vest on a pro-rata basis due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For vested and undistributed performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period. |
| |
| (c) | Does not include 503,283 of performance share units and 79,854 of restricted stock units that were vested and undistributed. |
Performance Share Units
A performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of
the three-year performance period, certain specified performance or market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. The vesting period for share units awarded extends beyond the three-year performance period to the payout date.
The following table summarizes the nonvested performance share unit activity for the year ended December 31, 2017:
|
| | | | | | |
| | Performance Share Units |
| | Share Units | | Weighted-average Grant Date Fair Value per Share Unit |
Nonvested at January 1, 2017(a) | 780,545 |
| | $ | 47.54 |
|
Granted(b) | 508,161 |
| | 59.16 |
|
| Forfeitures | (50,523 | ) | | 52.50 |
|
Undistributed vested units(c) | (342,694 | ) | | 51.65 |
|
Nonvested at December 31, 2017(a) | 895,489 |
| | $ | 52.28 |
|
| |
(a) | Excludes 369,878 and 712,572 performance share units granted to retirement-eligible employees as of January 1, 2017 and December 31, 2017, respectively, as the undistributed performance share units are fully vested. |
| |
(b) | Includes performance share units granted to certain executive and nonexecutive officers and other eligible employees in 2017 under the 2014 Incentive Plan. |
| |
(c) | Includes performance share units that 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 following table presents the stock-based compensation expense for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 4 |
| | $ | 4 |
| | $ | 5 |
|
| Ameren Illinois | 2 |
| | 2 |
| | 3 |
|
Other(a) | 12 |
| | 11 |
| | 11 |
|
| Ameren | 18 |
| | 17 |
| | 19 |
|
| Less income tax benefit | 7 |
| | 6 |
| | 7 |
|
| Stock-based compensation expense, net | $ | 11 |
| | $ | 11 |
| | $ | 12 |
|
| |
(a) | Represents compensation expense of employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above. |
Ameren settled performance share units of $39 million, $83 million, and $27 million for the years ended December 31, 2017, 2016, and 2015. There were no significant compensation costs capitalized related to the performance share units during the years ended December 31, 2017, 2016, and 2015. As of December 31, 2017, total compensation cost of $29 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.
The fair value of each share unit awarded under the 2014 Incentive Plan is based on Ameren’s closing common share price at December 31st of the year prior to the award year and lattice simulations. Lattice simulations area Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on Ameren’s total shareholder returnTSR for a 3-yearthree-year performance period relative to the designated peer group beginning January 1st of the award year. The simulationssimulation can produce a greater fair value for the share unit than the applicable closing common share price because they includeit includes the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also include a three-yearthree-year risk-free rate, Ameren’s common stock volatility, volatility for the peer group, and Ameren’s attainment of a three-yearthree-year average earnings per share threshold during the performance period. The following table presents the fair value of each share unit awarded under the 2014 Incentive Plan along with the significant assumptions used to calculate the fair value of each share unit for the years ended December 31, 2017, 2016,2019, 2018, and 2015:2017:
|
| | | |
| | 2017 | 2016 | 2015 |
| Fair value of share units awarded | $59.16 | $44.13 | $52.88 |
| Ameren’s closing common share price at December 31 of the prior year | $52.46 | $43.23 | $46.13 |
| Three-year risk free rate | 1.47% | 1.31% | 1.10% |
| Volatility range | 15% - 21% | 15% - 20% | 12% - 18% |
|
| | | |
| | 2019 | 2018 | 2017 |
| Fair value of share units awarded | $67.42 | $62.88 | $59.16 |
| Three-year risk-free rate | 2.46% | 1.98% | 1.47% |
Ameren’s common stock volatility(a) | 17% | 17% | 19% |
Volatility range for the peer group(a) | 15% – 25% | 15% – 23% | 15% – 21% |
| |
| (a) | Based on a historical period that is equal to the remaining term of the performance period as of the grant date. |
Restricted Stock Units
Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. Generally, in the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date. Stock-Based Compensation Expense
The following table presents the stock-based compensation expense for the years ended December 31, 2019, 2018, and 2017:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Ameren Missouri | $ | 4 |
| | $ | 4 |
| | $ | 4 |
|
| Ameren Illinois | 3 |
| | 3 |
| | 2 |
|
Other(a) | 13 |
| | 13 |
| | 12 |
|
| Ameren | 20 |
| | 20 |
| | 18 |
|
| Less income tax benefit | 5 |
| | 6 |
| | 7 |
|
| Stock-based compensation expense, net | $ | 15 |
| | $ | 14 |
| | $ | 11 |
|
| |
| (a) | Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above. |
Ameren settled performance share units and restricted stock units of $83 million, $54 million, and $39 million for the years ended December 31, 2019, 2018, and 2017. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2019, 2018, and 2017. As of December 31, 2019, total compensation cost of $28 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.
For the years ended December 31, 2019, 2018, and 2017, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $15 million, $6 million, and $4 million, respectively.
NOTE 12 – INCOME TAXES
Federal Tax Reform
The TCJA was enacted on December 22, 2017. Substantially all of the provisions of the TCJA affecting the Ameren Companies, other than certain transition depreciation rules, are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code, including amendments that significantly change the taxation of business entities and specific provisions related to regulated public utilities. The most significant change that affects the Ameren Companies is the reduction in the federal
corporate statutory income tax rate from 35% to 21%. Specific provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, the elimination of accelerated depreciation tax benefits from certain regulated utility capital investments acquired after September 27, 2017, and the continuation of certain rate normalization requirements related to the flow back of excess deferred income taxes. Ameren (parent) will beis subject to provisions of the TCJA that limit the deductibility of interest expense.expense, but such limitation did not affect Ameren in 2018 or 2019.
In accordance with GAAP, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. GAAP also requires deferred tax assets and liabilities to be measured at the tax rate that is expected to apply when temporary differences are realized or settled. Thus, in December 2017, the Ameren Companies’ deferred taxes were revalued using the new tax rate. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes was deferred as a regulatory asset or liability on the balance sheet and will be collected from, or refunded, to customers. For deferred tax balances not included in rate base, the revaluation of deferred taxes was recorded as income tax expense.
As a result of During the complexity of the TCJA, the SEC staff issued guidance to clarify the accounting for income taxes if information is not yet available or complete. This guidance provides for up to a one year period in which to complete the required analysis and update provisional estimates. The guidance provides three scenarios associated with a company’s status of accounting for income tax reform: (1) a company has completed itsaccounting for certain effects of tax reform, (2) a company is able to make areasonable estimate for certain effects of tax reform and records that estimate as aprovisional amount, or (3) a company is not able to make a reasonable estimate andtherefore continues to apply income tax accounting that is based on the taxlaws in effect immediately prior to the enactment of the TCJA.
As ofended December 31, 2017, the Ameren, Companies have made reasonable estimates for the measurementAmeren Missouri, and accounting of certain effects of the TCJA, which have been reflected in their financial statements. We haveAmeren Illinois recorded provisional estimates of $154 million, $32 million, and ($5) million, respectively, of income tax expense (benefit) primarily related to depreciation transition rules and 2017 property, plant, and equipment, compensation, and pension-related deductions which would impact our revaluation of deferred taxes at December 31, 2017. These items may be resolved through additional analysis, which is incomplete due to the timing of the enactment of the TCJA and complexity associated with applying its provisions. Additionally, interpretations, regulations, amendments, and technical corrections of the TCJA by various regulators could also resolve provisional items. The TCJA had the following provisional effects fordeductions. During the year ended December 31, 2017: |
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| Increase (Decrease) | | | | | | | |
| Accumulated deferred income taxes, net | $ | (1,419 | ) | | $ | (871 | ) | | $ | 37 |
| | $ | (2,253 | ) |
Income tax expense (benefit)(a) | 32 |
| | (5 | ) | | 127 |
| | 154 |
|
| Noncurrent regulatory assets | (89 | ) | | (24 | ) | | (1 | ) | | (114 | ) |
| Noncurrent regulatory liabilities | 1,362 |
| | 842 |
| | 89 |
| | 2,293 |
|
For our regulated operations, reductions in accumulated deferred income tax balances due to the reduction in the federal statutory corporate income tax rate to 21% will result in amounts previously collected from utility customers for these deferred taxes being refundable to those customers, generally through reductions in future rates. The TCJA includes provisions related to the IRS normalization rules that address the time period in which certain plant-related components of the excess deferred income taxes are to be reflected in customer rates. This time period for the Ameren Companies is approximately 3525 to 6065 years. Other components of the excess deferred income taxes will be reflected in customer rates as determined by our state and federal regulators, which could be a shorter time period than that applicable to certain plant-related components. See Note 2 –
Missouri Income Tax Rate
In 2018, legislation modifying Missouri tax law was enacted to decrease the state’s corporate income tax rate from 6.25% to 4%, effective January 1, 2020. As a result, in 2018, Ameren’s and Regulatory Matters for information regardingAmeren Missouri’s accumulated deferred tax balances were revalued, resulting in a net decrease of $122 million to their accumulated deferred tax liability, which was offset by a regulatory liability. Additionally, Ameren recorded an immaterial amount to income tax expense. Ameren Missouri anticipates that the various proceedings for the TCJA impacts with our regulators.effect of this tax decrease will be reflected in customer rates upon completion of its current electric service regulatory rate review. Ameren (parent) and nonregistrant subsidiaries do not expect this income tax decrease to have a material impact on net income.
Illinois Income Tax Rate
In July 2017, Illinois enacted a law that increased the state’s corporate income tax rate from 7.75% to 9.5% as of July 1, 2017. The law made the increase in the state’s corporate income taxrate permanent. That rate was previously scheduled to go to 7.3% in 2025. In July 2017, Ameren recorded an expense of $14 million at Ameren (parent) due to the revaluation of accumulated deferred taxes and the estimated state apportionment of such taxes. Beyond this expense, Ameren doesand Ameren Illinois do not expect this tax increase to have a material impact on its consolidatedtheir net income prospectively. The tax increase is not expected to materially impactaffect the earnings of the Ameren Illinois Electric Distribution, the Ameren Transmission, or the Ameren Illinois Transmission segments, since these businesses operate under formula ratemaking frameworks. The tax increase unfavorably affected the 2017 net income of the Ameren Illinois Natural Gas segment by less than $1 million. In addition, in the third quarter of 2017, Ameren’s and Ameren Illinois’ accumulated deferred tax balances were revalued using the state’s new corporate income tax rate, which resulted in a net increase to the liability balances of $97 million and $79 million, respectively. These increased liabilities were offset by a regulatory asset, as well as income tax expense, as discussed above.
The following table presents the principal reasons for the difference between the effective income tax rate and the federal statutory corporate income tax rate for the years ended December 31, 20172019, 20162018, and 20152017:
|
| | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2019 | | | | | |
| Federal statutory corporate income tax rate: | 21 | % | | 21 | % | | 21 | % |
| Increases (decreases) from: | | | | | |
| Amortization of excess deferred income taxes | (11 | ) | | (4 | ) | | (7 | ) |
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 5 |
| | 7 |
| | 6 |
|
| Stock-based compensation | — |
| | — |
| | (1 | ) |
| Effective income tax rate | 14 | % | | 24 | % | | 18 | % |
| 2018 | | | | | |
| Federal statutory corporate income tax rate: | 21 | % | | 21 | % | | 21 | % |
| Increases (decreases) from: | | | | | |
| Amortization of excess deferred income taxes | (4 | ) | | (4 | ) | | (4 | ) |
| Depreciation differences | — |
| | (1 | ) | | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 4 |
| | 7 |
| | 6 |
|
| TCJA | 1 |
| | 1 |
| | 1 |
|
| Tax credits | (1 | ) | | — |
| | — |
|
| Other permanent items | — |
| | — |
| | (1 | ) |
| Effective income tax rate | 20 | % | | 24 | % | | 22 | % |
| 2017 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | 1 |
| | (1 | ) | | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 4 |
| | 6 |
| | 6 |
|
| TCJA | 6 |
| | (1 | ) | | 14 |
|
| Tax credits | (1 | ) | | — |
| | — |
|
| Other permanent items | — |
| | (1 | ) | | (2 | ) |
| Effective income tax rate | 44 | % | | 38 | % | | 52 | % |
|
| | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2017 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | 1 |
| | (1 | ) | | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 4 |
| | 6 |
| | 6 |
|
| TCJA | 6 |
| | (1 | ) | | 14 |
|
| Tax credits | (1 | ) | | — |
| | — |
|
| Other permanent items | — |
| | (1 | ) | | (2 | ) |
| Effective income tax rate | 44 | % | | 38 | % | | 52 | % |
| 2016 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | 1 |
| | — |
| | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | — |
|
| State tax | 3 |
| | 5 |
| | 4 |
|
Stock-based compensation(a) | — |
| | — |
| | (2 | ) |
| Valuation allowance | — |
| | — |
| | 1 |
|
| Other permanent items | — |
| | (2 | ) | | (1 | ) |
| Effective income tax rate | 38 | % | | 38 | % | | 37 | % |
| 2015 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | — |
| | (2 | ) | | (1 | ) |
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 3 |
| | 5 |
| | 5 |
|
| Other permanent items | — |
| | (1 | ) | | — |
|
| Effective income tax rate | 37 | % | | 37 | % | | 38 | % |
| |
(a) | Reflects the adoption of authoritative accounting guidance related to share-based compensation, which resulted in the recognition of a $21 million income tax benefit in 2016. |
The following table presents the components of income tax expense for the years ended December 31, 20172019, 20162018, and 20152017: |
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2019 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 65 |
| | $ | 19 |
| | $ | (88 | ) | | $ | (4 | ) |
| State | 22 |
| | 11 |
| | (14 | ) | | 19 |
|
| Deferred taxes: | | | | | | | |
| Federal | 37 |
| | 66 |
| | 82 |
| | 185 |
|
| State | 5 |
| | 29 |
| | 25 |
| | 59 |
|
| Amortization of excess deferred income taxes | (56 | ) | | (15 | ) | | (1 | ) | | (72 | ) |
| Amortization of deferred investment tax credits | (5 | ) | | — |
| | — |
| | (5 | ) |
| Total income tax expense | $ | 68 |
| | $ | 110 |
| | $ | 4 |
| | $ | 182 |
|
| 2018 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 104 |
| | $ | 4 |
| | $ | (118 | ) | | $ | (10 | ) |
| State | 29 |
| | 6 |
| | (12 | ) | | 23 |
|
| Deferred taxes: | | | | | | | |
| Federal | 22 |
| | 75 |
| | 123 |
| | 220 |
|
| State | (2 | ) | | 28 |
| | 23 |
| | 49 |
|
| Amortization of excess deferred income taxes | (24 | ) | | (15 | ) | | (1 | ) | | (40 | ) |
| Amortization of deferred investment tax credits | (5 | ) | | — |
| | — |
| | (5 | ) |
| Total income tax expense | $ | 124 |
| | $ | 98 |
| | $ | 15 |
| | $ | 237 |
|
| 2017 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 149 |
| | $ | (34 | ) | | $ | (110 | ) | | $ | 5 |
|
| State | 23 |
| | 29 |
| | (20 | ) | | 32 |
|
| Deferred taxes: | | | | | | | |
| Federal | 76 |
| | 185 |
| | 250 |
| | 511 |
|
| State | 11 |
| | (13 | ) | | 36 |
| | 34 |
|
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 254 |
| | $ | 166 |
| | $ | 156 |
| | $ | 576 |
|
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2017 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 149 |
| | $ | (34 | ) | | $ | (110 | ) | | $ | 5 |
|
| State | 23 |
| | 29 |
| | (20 | ) | | 32 |
|
| Deferred taxes: | | | | | | | |
| Federal | 76 |
| | 185 |
| | 250 |
| | 511 |
|
| State | 11 |
| | (13 | ) | | 36 |
| | 34 |
|
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 254 |
| | $ | 166 |
| | $ | 156 |
| | $ | 576 |
|
| 2016 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 31 |
| | $ | (8 | ) | | $ | (24 | ) | | $ | (1 | ) |
| State | 6 |
| | 12 |
| | (21 | ) | | (3 | ) |
| Deferred taxes: | | | | | | | |
| Federal | 161 |
| | 117 |
| | 21 |
| | 299 |
|
| State | 23 |
| | 37 |
| | 32 |
| | 92 |
|
| Amortization of deferred investment tax credits | (5 | ) | | — |
| | — |
| | (5 | ) |
| Total income tax expense | $ | 216 |
| | $ | 158 |
| | $ | 8 |
| | $ | 382 |
|
| 2015 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 110 |
| | $ | (83 | ) | | $ | (29 | ) | | $ | (2 | ) |
| State | 17 |
| | (11 | ) | | (10 | ) | | (4 | ) |
| Deferred taxes: | | | | | | | |
| Federal | 71 |
| | 193 |
| | 35 |
| | 299 |
|
| State | 16 |
| | 29 |
| | 31 |
| | 76 |
|
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 209 |
| | $ | 127 |
| | $ | 27 |
| | $ | 363 |
|
The following table presents the accumulated deferred income tax assets and liabilities recorded as a result of temporary differences and accumulated deferred investment tax credits at December 31, 20172019 and 20162018:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2019 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,000 |
| | $ | 1,423 |
| | $ | 193 |
| | $ | 3,616 |
|
| Regulatory assets and liabilities, net | (310 | ) | | (214 | ) | | (24 | ) | | (548 | ) |
| Deferred employee benefit costs | (59 | ) | | 7 |
| | (59 | ) | | (111 | ) |
| Tax carryforwards | (25 | ) | | (3 | ) | | (70 | ) | | (98 | ) |
| Other | (33 | ) | | 11 |
| | 43 |
| | 21 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 1,573 |
| | $ | 1,224 |
| | $ | 83 |
| | $ | 2,880 |
|
| Accumulated deferred investment tax credits | 39 |
| | — |
| | — |
| | 39 |
|
| Accumulated deferred income taxes and investment tax credits | $ | 1,612 |
| | $ | 1,224 |
| | $ | 83 |
| | $ | 2,919 |
|
| 2018 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,010 |
| | $ | 1,345 |
| | $ | 179 |
| | $ | 3,534 |
|
| Regulatory assets and liabilities, net | (343 | ) | | (221 | ) | | (25 | ) | | (589 | ) |
| Deferred employee benefit costs | (58 | ) | | (4 | ) | | (64 | ) | | (126 | ) |
| Tax carryforwards | (35 | ) | | (26 | ) | | (166 | ) | | (227 | ) |
| Other | (40 | ) | | 24 |
| | 47 |
| | 31 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 1,534 |
| | $ | 1,118 |
| | $ | (29 | ) | | $ | 2,623 |
|
| Accumulated deferred investment tax credits | 42 |
| | 1 |
| | — |
| | 43 |
|
| Accumulated deferred income taxes and investment tax credits | $ | 1,576 |
| | $ | 1,119 |
| | $ | (29 | ) | | $ | 2,666 |
|
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2017 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant related | $ | 2,064 |
| | $ | 1,264 |
| | $ | 146 |
| | $ | 3,474 |
|
| Regulatory assets and liabilities, net | (317 | ) | | (206 | ) | | (24 | ) | | (547 | ) |
| Deferred employee benefit costs | (53 | ) | | (17 | ) | | (61 | ) | | (131 | ) |
| Revenue requirement reconciliation adjustments | — |
| | 20 |
| | — |
| | 20 |
|
| Tax carryforwards | (31 | ) | | (43 | ) | | (287 | ) | | (361 | ) |
| Other | (13 | ) | | 3 |
| | 61 |
| | 51 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 1,650 |
| | $ | 1,021 |
| | $ | (165 | ) | | $ | 2,506 |
|
| 2016 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant related | $ | 3,103 |
| | $ | 1,769 |
| | $ | 147 |
| | $ | 5,019 |
|
| Regulatory assets and liabilities, net | 75 |
| | (1 | ) | | — |
| | 74 |
|
| Deferred employee benefit costs | (76 | ) | | (38 | ) | | (97 | ) | | (211 | ) |
| Revenue requirement reconciliation adjustments | — |
| | 34 |
| | — |
| | 34 |
|
| Tax carryforwards | (66 | ) | | (138 | ) | | (472 | ) | | (676 | ) |
| Other | (23 | ) | | 5 |
| | 42 |
| | 24 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 3,013 |
| | $ | 1,631 |
| | $ | (380 | ) | | $ | 4,264 |
|
The following table presents the components of accumulated deferred income tax assets relating to net operating loss carryforwards, tax credit carryforwards, and charitable contribution carryforwards at December 31, 20172019 and 2016:2018:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2019 | | | | | | | |
| Tax credit carryforwards: | | | | | | | |
Federal(a) | $ | 25 |
| | $ | 3 |
| | $ | 67 |
| | $ | 95 |
|
State(b) | — |
| | — |
| | 3 |
| | 3 |
|
| Total tax credit carryforwards | $ | 25 |
| | $ | 3 |
| | $ | 70 |
| | $ | 98 |
|
Charitable contribution carryforwards(c) | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | 3 |
|
Valuation allowance(c) | — |
| | — |
| | (3 | ) | | (3 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2018 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| Federal | $ | — |
| | $ | 23 |
| | $ | 55 |
| | $ | 78 |
|
| State | — |
| | — |
| | 13 |
| | 13 |
|
| Total net operating loss carryforwards | $ | — |
| | $ | 23 |
| | $ | 68 |
| | $ | 91 |
|
| Tax credit carryforwards: | | | | | | | |
| Federal | $ | 35 |
| | $ | 3 |
| | $ | 79 |
| | $ | 117 |
|
| State | — |
| | — |
| | 10 |
| | 10 |
|
| Total tax credit carryforwards | $ | 35 |
| | $ | 3 |
| | $ | 89 |
| | $ | 127 |
|
| Charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | 14 |
|
| Valuation allowance | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | 9 |
|
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2017 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
Federal(a) | $ | — |
| | $ | 41 |
| | $ | 162 |
| | $ | 203 |
|
State(a) | — |
| | — |
| | 32 |
| | 32 |
|
| Total net operating loss carryforwards | $ | — |
| | $ | 41 |
| | $ | 194 |
| | $ | 235 |
|
| Tax credit carryforwards: | | | | | | | |
Federal(b) | $ | 31 |
| | $ | 2 |
| | $ | 80 |
| | $ | 113 |
|
State(c) | — |
| | — |
| | 7 |
| | 7 |
|
| Total tax credit carryforwards | $ | 31 |
| | $ | 2 |
| | $ | 87 |
| | $ | 120 |
|
Charitable contribution carryforwards(d) | $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 11 |
|
Valuation allowance(e) | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
|
| 2016 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| Federal | $ | 33 |
| | $ | 137 |
| | $ | 324 |
| | $ | 494 |
|
| State | 4 |
| | — |
| | 41 |
| | 45 |
|
| Total net operating loss carryforwards | $ | 37 |
| | $ | 137 |
| | $ | 365 |
| | $ | 539 |
|
| Tax credit carryforwards: | | | | | | | |
| Federal | $ | 29 |
| | $ | 1 |
| | $ | 79 |
| | $ | 109 |
|
| State | — |
| | — |
| | 21 |
| | 21 |
|
| Total tax credit carryforwards | $ | 29 |
| | $ | 1 |
| | $ | 100 |
| | $ | 130 |
|
| Charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | 18 |
|
| Valuation allowance | — |
| | — |
| | (11 | ) | | (11 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 7 |
|
| |
| (a) | Will expire between 20332029 and 2036. Any net operating loss carryforward generated after January 1, 2018, will not have an expiration date as a result of the TCJA.2039. |
| |
| (b) | Will expire between 20292022 and 2037.2024. |
| |
| (c) | Will expire between2019 and 2022. |
| |
(d) | Will expire between 2018 and 2021. |
| |
(e) | See Schedule II under Part IV, Item 15, in this report for information on changes in the valuation allowance. |
Uncertain Tax Positions
As of December 31, 20172019 and 2016,2018, the Ameren Companies did not record any uncertain tax positions.
In 2015, final settlements forThe Internal Revenue Service is currently examining Ameren’s 2018 federal income tax years 2012 and 2013 were reached with the IRS. The 2015 settlement of the 2013 tax year affected discontinued operations. See Note 1 – Summary of Significant Accounting Policies for additional information.
return. State income tax returns are generally subject to examination for a period of three years after filing. The state impact of any federal changes remains subject to examination by various states for up to one year after formal notification to the states. The Ameren Companies currently do not have material state income tax issues under examination, administrative appeals, or litigation.
Ameren Missouri has an uncertain tax position tracker. Under Missouri’s regulatory framework, uncertain tax positions do not reduce Ameren Missouri’s electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value, usingwith a return at the weighted-average cost of capitalapplicable WACC included in each of the electric rate orders in effect before the tax position was resolved, of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will affect earnings in the year it is created. It will then will be amortized over three years, beginning on the effective date of new rates established in the next electric service regulatory rate review.
NOTE 13 – RELATED-PARTY TRANSACTIONS
In the normal course of business, Ameren Missouri and Ameren Illinois have engaged in, and may in the future engage in affiliate transactions. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements.statements, except as noted in Software Licensing Agreement discussion below. Below are the material related-party agreements.
Electric Power Supply Agreements
Ameren Illinois must acquire capacity and energy sufficient to meet its obligations to customers. Ameren Illinois uses periodic RFP processes, administered by the IPA and approved by the ICC, to contract capacity and energy on behalf of its customers. Ameren Missouri participates in the RFP process and has been a winning supplier for certain periods.
Capacity Supply Agreements
In a procurement event in 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $3 million for the 12 months ended May 31, 2015. In a procurement event in 2015, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $15 million for the 12 months ending May 31, 2017.
Energy Swaps and Energy Products
Based on the outcome of IPA-administered procurement events, Ameren Missouri and Ameren Illinois have entered into energy product agreements by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, a set amount of megawatthours at a predetermined price over a specified period of time. The following table presents the agreements the companies have entered into, as well as the specified performance period, price, and amount of megawatthours included in each agreement:the agreements:
|
| | | | | | |
| IPA Procurement Event | Performance Period | MWh | | Average Price per MWh |
| September 2015 | November 2015 – May 2018 | 339,000 | | $ | 38 |
|
| April 2016 | June 2017 – September 2018 | 375,200 | | 35 |
|
| September 2016 | May 2017 – September 2018 | 82,800 | | 34 |
|
| April 2017 | March 2019 – May 2020 | 85,600 | | 34 |
|
| April 2018 | June 2019 – September 2020 | 110,000 | | 32 |
|
| April 2019 | January 2020 – December 2021 | 288,000 | | 35 |
|
| September 2019 | April 2020 – November 2021 | 170,800 | | 29 |
|
|
| | | | | |
| IPA Procurement Event | Performance Period | MWh |
| | Average Price per MWh |
| May 2014 | January 2015 – February 2017 | 168,400 |
| $ | 51 |
| April 2015 | June 2015 – June 2017 | 667,000 |
| | 36 |
| September 2015 | November 2015 – May 2018 | 339,000 |
| | 38 |
| April 2016 | June 2017 – September 2018 | 375,200 |
| | 35 |
| September 2016 | May 2017 – September 2018 | 82,800 |
| | 34 |
| April 2017 | March 2019 – May 2020 | 85,600 |
| | 34 |
Collateral Postings
Under the terms of the Illinois energy product agreements entered into through RFP processes administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, which means that only the suppliers can be required to post collateral. Therefore, Ameren Missouri, as a winning supplier in the RFP process, may be required to post collateral. As of December 31, 20172019 and 2016,2018, there were no collateral postings required of Ameren Missouri related to the Illinois energy product agreements.
Interconnection and Transmission Agreements
Ameren Missouri and Ameren Illinois are parties to an interconnection agreement for the use of their respective transmission lines and other facilities for the distribution of power. These agreements have no contractual expiration date, but may be terminated by either party with three years’ notice.
Support Services Agreements
Ameren Services provides support services to its affiliates. The costs of support services including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The support services agreement can be terminated at any time by the mutual agreement of Ameren Services and that affiliate or by either party with 60 days’ notice before the end of a calendar year.
In addition, Ameren Missouri and Ameren Illinois provide affiliates primarily Ameren Services, with access to their facilities for administrative purposes.purposes and with use of other assets. The costs of the rent and facility services and other assets are based on, or are an allocation of, actual costs incurred.
Separately, Ameren Missouri and Ameren Illinois also provide storm-related and miscellaneous support services to each other on an as-needed basis.
Transmission Services
Ameren Illinois receives transmission services from ATXI for its retail loadload.
Electric Transmission Maintenance and Construction Agreements
ATXI entered into separate agreements with Ameren Missouri and Ameren Illinois in the AMIL pricing zone.
which Ameren Missouri or Ameren Illinois, as applicable, may perform certain maintenance and construction services related to ATXI’s electric transmission assets.
Money Pool
See Note 4 – Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.
Software Licensing Agreement
In September 2019, Ameren Missouri purchased a license for advanced metering infrastructure software from Ameren Illinois. The amount of the $24 million cost-based transaction price over the $5 million remaining carrying value of the software was recorded as revenue by Ameren Illinois, with $14 million of revenue recorded at Ameren Illinois Electric Distribution and $5 million recorded at Ameren Illinois
Natural Gas. The revenue recorded at Ameren Illinois Electric Distribution was reflected in formula ratemaking, which resulted in no impact to net income. Per authoritative accounting guidance for sales to rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation by Ameren. Ameren Missouri’s $24 million software investment is included in “Property, Plant, and Equipment, Net.”
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreement. As of December 31, 2017 and 2016,The following table presents the affiliate balances related to income taxes for Ameren Missouri had income taxes payable toand Ameren (parent) of $11 million and $16 million, respectively, included in “Accounts payable - affiliates” on its balance sheet. As of December 31, 2017 and 2016, Ameren Illinois had income taxes payable to Ameren (parent) of $17 million and $3 million, respectively, included in “Accounts payable - affiliates” on its balance sheet. See below for capital contributions received related to the tax allocation agreement.
Capital Contributions
In 2017, Ameren Missouri received cash capital contributions of $30 million from Ameren (parent) as a result of the tax allocation agreement. In 2017, Ameren Illinois received cash capital contributions of $8 million from Ameren (parent).
In 2016, Ameren Missouri received cash capital contributions of $44 million from Ameren (parent) as a result of the tax allocation agreement, which included the accrued capital contribution from 2015.
In 2015, Ameren Missouri received cash capital contributions of $224 million from Ameren (parent) as a result of the tax allocation agreement, which included the accrued capital contribution from 2014. Additionally, as of December 31, 2015, Ameren Missouri accrued a $38 million capital contribution related to the same agreement. In 2015, Ameren Illinois received2019 and 2018:
|
| | | | | | | | | | | | | | |
| | 2019 | | | 2018 |
| | Ameren Missouri | Ameren Illinois | | | Ameren Missouri | Ameren Illinois |
Income taxes payable to parent(a) | $ | 15 |
| $ | 43 |
| | | $ | 16 |
| $ | 7 |
|
Income taxes receivable from parent(b) | 15 |
| 17 |
| | | — |
| 6 |
|
| |
| (a) | Included in “Accounts payable – affiliates” on the balance sheet. |
| |
| (b) | Included in “Accounts receivable – affiliates” on the balance sheet. |
Capital Contributions
The following table presents cash capital contributions of $25 millionreceived from Ameren (parent). by Ameren Missouri and Ameren Illinois for the years ended December 31, 2019, 2018, and 2017:
|
| | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | |
Ameren Missouri(a) | $ | 124 |
| | $ | 45 |
| | $ | 30 |
| |
| Ameren Illinois | 15 |
| (a) | 160 |
| | 8 |
| |
| |
| (a) | As a result of the tax allocation agreement. |
Effects of Related-party Transactions on the Statement of Income
The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the years ended December 31, 2017, 2016,2019, 2018, and 2015.2017. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 – Short-term Debt and Liquidity.
| | | Agreement | Income Statement Line Item | | Ameren Missouri | | Ameren Illinois | Income Statement Line Item | | Ameren Missouri | | Ameren Illinois |
| Ameren Missouri power supply agreements | Operating Revenues | | 2017 | $ | 23 |
| $ | (a) |
| Operating Revenues | | 2019 | $ | 3 |
| $ | (a) |
|
| with Ameren Illinois | | 2016 | | 28 |
| | (a) |
| | 2018 | | 11 |
| | (a) |
|
| | | | 2015 | | 15 |
| | (a) |
| | | 2017 | | 23 |
| | (a) |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2017 | | 26 |
| | 4 |
| Operating Revenues | | 2019 | | 27 |
| | 2 |
|
| rent and facility services | | 2016 | | 25 |
| | 5 |
| | 2018 | | 22 |
| | 3 |
|
| | | | 2015 | | 25 |
| | 4 |
| | | 2017 | | 26 |
| | 4 |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2017 | | (b) |
| | 1 |
| |
| miscellaneous support services | | 2016 | | 1 |
| | (b) |
| |
| Ameren Missouri and Ameren Illinois miscellaneous | | Operating Revenues | | 2019 | | 1 |
| | 2 |
|
| support services and services provided to ATXI | | | 2018 | | 1 |
| | 1 |
|
| | | | 2017 | | (b) |
| | 1 |
|
| Ameren Missouri software licensing | | Operating Revenues | | 2019 | | (a) |
| | 19 |
|
| with Ameren Illinois | | | 2018 | | (a) |
| | (a) |
|
| | | 2015 | | 2 |
| | (b) |
| | 2017 | | (a) |
| | (a) |
|
| Total Operating Revenues | | 2017 | $ | 49 |
| $ | 5 |
| | 2019 | $ | 31 |
| $ | 23 |
|
| | | 2016 | | 54 |
| | 5 |
| | 2018 | | 34 |
| | 4 |
|
| | | | 2015 | | 42 |
| | 4 |
| | | 2017 | | 49 |
| | 5 |
|
| Ameren Illinois power supply | Purchased Power | | 2017 | $ | (a) |
| $ | 23 |
| Purchased Power | | 2019 | $ | (a) |
| $ | 3 |
|
| agreements with Ameren Missouri | | 2016 | | (a) |
| | 28 |
| | 2018 | | (a) |
| | 11 |
|
| | | | 2015 | | (a) |
| | 15 |
| | | 2017 | | (a) |
| | 23 |
|
| Ameren Illinois transmission | Purchased Power | | 2017 | | (a) |
| | 2 |
| Purchased Power | | 2019 | | (a) |
| | 2 |
|
| services from ATXI | | 2016 | | (a) |
| | 2 |
| | 2018 | | (a) |
| | 1 |
|
| | | 2015 | | (a) |
| | 2 |
| | 2017 | | (a) |
| | 2 |
|
| Total Purchased Power | | 2017 | $ | (a) |
| $ | 25 |
| | 2019 | $ | (a) |
| $ | 5 |
|
| | | 2016 | | (a) |
| | 30 |
| | 2018 | | (a) |
| | 12 |
|
| | | 2015 | | (a) |
| | 17 |
| | 2017 | | (a) |
| | 25 |
|
| Ameren Missouri and Ameren Illinois | | Other Operations and | | 2019 | $ | 2 |
| $ | 5 |
|
| rent and facility services | | Maintenance | | 2018 | | 3 |
| | 6 |
|
| | | | 2017 | | (b) |
| | (b) |
|
| Ameren Services support services | Other Operations and | | 2017 | $ | 149 |
| $ | 139 |
| Other Operations and | | 2019 | | 135 |
|
| 127 |
|
| agreement | Maintenance | | 2016 | | 129 |
| | 123 |
| Maintenance | | 2018 | | 136 |
| | 126 |
|
| | | | | 2017 | | 149 |
| | 139 |
|
| Total Other Operations and | | | 2019 | $ | 137 |
| $ | 132 |
|
| Maintenance Expenses | | | 2018 | | 139 |
| | 132 |
|
| | | | 2015 | | 131 |
| | 119 |
| | | 2017 | | 149 |
| | 139 |
|
| Money pool borrowings (advances) | (Interest Charges) | | 2017 | $ | 1 |
| $ | (b) |
| (Interest Charges) | | 2019 | $ | (b) |
| $ | (b) |
|
| | Miscellaneous Income | | 2016 | | (b) |
| | (b) |
| Other Income, Net | | 2018 | | 1 |
| | (b) |
|
| | | | 2015 | | (b) |
| | (b) |
| | | 2017 | | 1 |
| | (b) |
|
| |
| (b) | Amount less than $1 million. |
NOTE 14 – COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, 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 thesethe notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 13 – Related-party Transactions, and Note 15 – Supplemental Information in this report.
Leases
We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | After 5 Years | | Total |
Ameren:(a) | | | | | | | | | | | | | |
Minimum capital lease payments(b)(c) | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
| Operating leases | 10 |
| | 9 |
| | 8 |
| | 6 |
| | 6 |
| | 14 |
| | 53 |
|
| Total lease obligations | $ | 16 |
| | $ | 16 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 329 |
|
| Ameren Missouri: | | | | | | | | | | | | | |
Minimum capital lease payments(b)(c) | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
| Operating leases | 8 |
| | 8 |
| | 7 |
| | 6 |
| | 6 |
| | 14 |
| | 49 |
|
| Total lease obligations | $ | 14 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 325 |
|
| Ameren Illinois: | | | | | | | | | | | | | |
| Operating leases | $ | 1 |
| | (d) |
| | (d) |
| | (d) |
| | (d) |
| | $ | 1 |
| | $ | 2 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | See Note 3 – Property, Plant, and Equipment, Net for additional information. |
| |
(c) | See Note 5 – Long-term Debt and Equity Financings for additional information on Ameren’s and Ameren Missouri’s capital lease agreements. |
The following table presents total operating lease expenses included in “Operating Expenses” in the statement of income for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
Ameren(a) | $ | 11 |
| | $ | 38 |
| | $ | 36 |
|
| Ameren Missouri | 10 |
| | 34 |
| | 34 |
|
| Ameren Illinois | 1 |
| | 30 |
| | 28 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Other Obligations
To supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power, and other commitments at December 31, 20172019. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services, among other agreements, at December 31, 20172019.
| | | | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b)(c) | | Methane Gas | | Other | | Total | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b)(c) | | Methane Gas | | Other | | Total |
Ameren:(d) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | $ | 463 |
| | $ | 205 |
| | $ | 67 |
| | $ | 170 |
| | $ | 3 |
| | $ | 73 |
| | $ | 981 |
| |
| 2019 | 383 |
| | 163 |
| | 26 |
| | 63 |
| | 4 |
| | 37 |
| | 676 |
| |
| 2020 | 85 |
| | 110 |
| | 39 |
| | 14 |
| | 4 |
| | 36 |
| | 288 |
| $ | 325 |
| | $ | 171 |
| | $ | 42 |
| | $ | 147 |
| (d) | $ | 3 |
| | $ | 75 |
| | $ | 763 |
|
| 2021 | 27 |
| | 46 |
| | 45 |
| | 3 |
| | 5 |
| | 25 |
| | 151 |
| 197 |
| | 109 |
| | 60 |
| | 51 |
| | 3 |
| | 33 |
| | 453 |
|
| 2022 | — |
| | 11 |
| | 12 |
| | 2 |
| | 5 |
| | 25 |
| | 55 |
| 137 |
| | 55 |
| | 13 |
| | 13 |
| | 3 |
| | 22 |
| | 243 |
|
| 2023 | | 46 |
| | 35 |
| | 43 |
| | 3 |
| | 3 |
| | 22 |
| | 152 |
|
| 2024 | | 53 |
| | 12 |
| | 15 |
| | — |
| | 3 |
| | 25 |
| | 108 |
|
| Thereafter | — |
| | 38 |
| | 45 |
| | 18 |
| | 58 |
| | 95 |
| | 254 |
| 27 |
| | 43 |
| | 15 |
| | — |
| | 24 |
| | 58 |
| | 167 |
|
| Total | $ | 958 |
| | $ | 573 |
| | $ | 234 |
| | $ | 270 |
| | $ | 79 |
| | $ | 291 |
| | $ | 2,405 |
| $ | 785 |
| | $ | 425 |
| | $ | 188 |
| | $ | 214 |
| | $ | 39 |
| | $ | 235 |
| | $ | 1,886 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | $ | 463 |
| | $ | 42 |
| | $ | 67 |
| | $ | — |
| | $ | 3 |
| | $ | 53 |
| | $ | 628 |
| |
| 2019 | 383 |
| | 36 |
| | 26 |
| | — |
| | 4 |
| | 24 |
| | 473 |
| |
| 2020 | 85 |
| | 29 |
| | 39 |
| | — |
| | 4 |
| | 24 |
| | 181 |
| $ | 325 |
| | $ | 40 |
| | $ | 42 |
| | $ | — |
| | $ | 3 |
| | $ | 61 |
| | $ | 471 |
|
| 2021 | 27 |
| | 13 |
| | 45 |
| | — |
| | 5 |
| | 25 |
| | 115 |
| 197 |
| | 26 |
| | 60 |
| | — |
| | 3 |
| | 26 |
| | 312 |
|
| 2022 | — |
| | 6 |
| | 12 |
| | — |
| | 5 |
| | 25 |
| | 48 |
| 137 |
| | 14 |
| | 13 |
| | — |
| | 3 |
| | 22 |
| | 189 |
|
| 2023 | | 46 |
| | 13 |
| | 43 |
| | — |
| | 3 |
| | 22 |
| | 127 |
|
| 2024 | | 53 |
| | 6 |
| | 15 |
| | — |
| | 3 |
| | 25 |
| | 102 |
|
| Thereafter | — |
| | 16 |
| | 45 |
| | — |
| | 58 |
| | 75 |
| | 194 |
| 27 |
| | 19 |
| | 15 |
| | — |
| | 24 |
| | 24 |
| | 109 |
|
| Total | $ | 958 |
| | $ | 142 |
| | $ | 234 |
| | $ | — |
| | $ | 79 |
| | $ | 226 |
| | $ | 1,639 |
| $ | 785 |
| | $ | 118 |
| | $ | 188 |
| | $ | — |
| | $ | 39 |
| | $ | 180 |
| | $ | 1,310 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | $ | — |
| | $ | 163 |
| | $ | — |
| | $ | 170 |
| | $ | — |
| | $ | 19 |
| | $ | 352 |
| |
| 2019 | — |
| | 127 |
| | — |
| | 63 |
| | — |
| | 13 |
| | 203 |
| |
| 2020 | — |
| | 81 |
| | — |
| | 14 |
| | — |
| | 12 |
| | 107 |
| $ | — |
| | $ | 131 |
| | $ | — |
| | $ | 147 |
| (d) | $ | — |
| | $ | 3 |
| | $ | 281 |
|
| 2021 | — |
| | 33 |
| | — |
| | 3 |
| | — |
| | — |
| | 36 |
| — |
| | 83 |
| | — |
| | 51 |
| | — |
| | 2 |
| | 136 |
|
| 2022 | — |
| | 5 |
| | — |
| | 2 |
| | — |
| | — |
| | 7 |
| — |
| | 41 |
| | — |
| | 13 |
| | — |
| | — |
| | 54 |
|
| 2023 | | — |
| | 22 |
| | — |
| | 3 |
| | — |
| | — |
| | 25 |
|
| 2024 | | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
| Thereafter | — |
| | 22 |
| | — |
| | 18 |
| | — |
| | — |
| | 40 |
| — |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
|
| Total | $ | — |
| | $ | 431 |
| | $ | — |
| | $ | 270 |
| | $ | — |
| | $ | 44 |
| | $ | 745 |
| $ | — |
| | $ | 307 |
| | $ | — |
| | $ | 214 |
| | $ | — |
| | $ | 5 |
| | $ | 526 |
|
| |
| (a) | Includes amounts for generation and for distribution. |
| |
| (b) | The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 20322035 with various renewable energy suppliers due to the contingent nature of the payment amounts.amounts, with the exception of expected payments of $13 million through 2024. |
| |
| (c) | The purchased power amounts for Ameren and Ameren Missouri exclude a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts. |
| |
| (d) | IncludesIn January 2018, as required by the FEJA, Ameren Illinois entered into agreements to acquire zero emission credits, through 2026. Annual zero emission credit commitment amounts forwill be published by the IPA each May prior to the start of the subsequent planning year. The amounts above reflect Ameren registrant and nonregistrant subsidiaries.Illinois’ commitment to acquire approximately $27 million of zero emission credits through May 2020. |
Environmental Matters
We are subject to various environmental laws, including statutes and regulations, enforced by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect to environmental laws and regulations.laws. These laws and regulations address emissions, discharges to water, water usage,intake, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.
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, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% 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 revised 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
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.
Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $325$200 million to $425$250 million from 20182020 through 20222024 in order to comply with existing environmental regulations. Additional environmental controls beyond 20222024 could be required. This estimate of capital expenditures includes expenditures required by the CCR regulations, by the Clean Water Act rule applicable to cooling water intake structures at existing power plants, and by effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. This estimate does not include capital expenditures that may be required as a result of the NSR and Clean Air Act litigation discussed below. Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning low-sulfur coal and installing new or optimizing existing air pollution control equipment. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimate because of uncertainty as to whether the EPA will substantially revise regulatory obligations, exactly which compliance strategies will be used and their ultimate cost, among other things.
The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of several regulations and rulemaking activities,proposed amendments to regulations and guidelines, including to the effluent limitation guidelines and the CCR rule,Rule, which could ultimately result in the revision of all or part of such rules.
Clean Air Act
Federal and state laws, require significant reductions inincluding CSAPR, regulate emissions of SO2and NOx through either emissionthe reduction of emissions at their source reductions orand the use and retirement of emission allowances. The first phase of the CSAPR emission reduction requirements became effective in 2015. The second phase of emission reduction requirements, which were revised by the EPA in 2016, became effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfurlow-sulfur coal, operates two2 scrubbers at its Sioux energy center,Energy Center, and optimizes other existing air pollution control equipment. Ameren Missouri did not make additional capital investments to comply with the 2017 CSAPR requirements. However, Ameren Missouri expects to incur additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costs are expected to be recovered from customers through the FAC or higher base rates.
CO2 Emissions Standards
In 2015,July 2019, the EPA issued the Affordable Clean Power Plan,Energy Rule, which would have establishedestablishes emission guidelines for states to follow in developing plans to limit CO2 emissions standards applicablefrom coal-fired electric generating units. The EPA has identified certain efficiency measures as the best system of emission reduction for coal-fired electric generating units. The Affordable Clean Energy Rule went into effect on September 6, 2019. The rule requires the state of Missouri to existing power plants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In October 2017,develop a compliance plan and submit it to the EPA announcedfor approval by September 2022. The plan is expected to include a proposalstandard of performance for each affected generating unit. We are evaluating the impact of the adoption and implementation of the Affordable Clean Energy Rule and, along with other stakeholders, will be working with the state of Missouri to repealdevelop the Clean Power Plan. In December 2017,compliance plan submitted to the EPA issued an advanced notice of proposed rulemaking to solicit input from stakeholders as to how the EPA should regulate CO2 emissions from existing power plants under the Clean Air Act. Accordingly,EPA. At this time, we no longer expect the Clean Power Plan to take effect. However, the EPA may issue new requirements that would regulate CO2 emissions from existing power plants. We cannot predict the outcome of Missouri’s compliance plan development process. As such, the EPA’s future rulemaking orimpact on the outcome of any legal challenges relating to such future rulemakings, any of which could have an adverse effect on our results of operations, financial position, and liquidity.liquidity of Ameren and Ameren Missouri is uncertain. We also cannot predict the outcome of any potential legal challenges to the rule.
NSR and Clean Air Act Litigation
In January 2011, the Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The complaint, as amended in October 2013, allegedMissouri alleging that in performing projects at its coal-fired Rush Island coal-fired energy centerEnergy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling and, in September 2019, entered a final order that required Ameren Missouri to install a flue gas desulfurization system at the projects violated provisions ofRush Island Energy Center and a dry sorbent injection system at the Clean Air Act and Missouri law. The case then proceeded to the second phase to determine the actions required to remedy the violations foundLabadie Energy Center. There were no fines in the liability phase. The EPA previously withdrew all claims for penalties and fines. No date has been set byorder. In October 2019, Ameren Missouri appealed the district court for a trial on the remedy phase of the litigation. At the conclusion of both phases of the litigation, Ameren Missouri intends to appeal the liabilitycourt’s ruling to the United States Court of Appeals for the Eighth Circuit. Additionally, in October 2019, following a request by Ameren Missouri, the district court stayed implementation of the majority of its order’s requirements while the case is appealed. Ameren Missouri believes that the district court both misinterpreted and misapplied the law in its ruling. We are unable to predict the ultimate resolution of this matter. Based on the initial procedural schedule, the Court of Appeals for the Eighth Circuit is expected to hear oral arguments in 2020; however, it is under no deadline to issue a ruling in this case.
The ultimate resolution of this matter could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Among other things and subject to economic and regulatory considerations, resolution of this matter could result in increased capital expenditures for the installation of air pollution control equipment, as well as increased operations and maintenance expenses. WeBased upon engineering studies, capital expenditures to comply with the district court’s order for installation of a flue
gas desulfurization system at the Rush Island Energy Center are unableestimated at approximately $1 billion. Further, the flue gas desulfurization system would result in additional operation and maintenance expenses of $30 million to predict$50 million annually for the ultimate resolutionlife of this matterthe energy center. Engineering studies required to develop estimated capital expenditures and estimated additional operation and maintenance expenses for the Labadie Energy Center to comply with the district court’s order will not be undertaken while the case is under appeal. As a result of the district court’s stay, Ameren Missouri does not expect to make significant capital expenditures or incur operations and maintenance expenses related to the costs that might be incurred.
district court’s order while the case is under appeal.
Clean Water Act
In 2014,July 2018, the EPA issued its final ruleUnited States Court of Appeals for the Second Circuit upheld the EPA’s Section 316(b) Rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing the number of aquatic organisms impinged on the facility’sa power plant’s cooling water intake screens or entrained through the plant’s cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. TheRequirements of the rule will beare being implemented by Ameren Missouri during the permit renewal process of each energy center’s water discharge permit, between 2018 andwhich is expected to be completed by 2023.
Additionally, inIn 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines established national standards for water discharges that are based on the effectiveness of available control technology. The EPA’s 2015 rule prohibits effluent discharges of certain waste streams and imposes more stringent limitations on certain water discharges from power plants. In September 2017, the EPA published a rule that postponed the compliance dates by two years for the limitations applicable to two2 specific waste streams so that it could potentially revise those standards.
Both To meet the intakerequirements of the guidelines, Ameren Missouri is constructing wastewater treatment facilities and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications to the cooling water systems and water dischargedry ash handling systems at Ameren Missouri’s3 of its energy centers and if such investmentsis scheduled to complete the projects in 2020. Estimated capital expenditures to complete these projects are not recovered on a timely basisincluded in electric rates charged to Ameren Missouri’s customers.the CCR management compliance plan, discussed below.
CCR Management
In 2015, the EPA issued regulations regardingthe CCR rule, which established requirements for the management and disposal of CCR from coal-fired energy centers.power plants. These regulations affect CCR disposal and handling costs at Ameren Missouri’s energy centers. They require closureAmeren Missouri is in the process of closing its surface impoundments, if performance criteria relatingwith the last of such closures scheduled for 2023. The EPA issued revisions to groundwater impacts and location restrictions are not achieved. In September 2017, the EPA granted petitions filed on behalf of coal-fired electricity generators in which the EPA agreed to reconsider certain provisions of the CCR rules.rule in July 2018, proposed additional revisions in July and November 2019, and indicated that additional revisions to the CCR rule are likely. Ameren and Ameren Missouri have AROs of $150$151 million recorded on their respective balance sheets as of December 31, 2017,2019, associated with CCR storage facilities that reflect the regulations issued in 2015.facilities. Ameren plans to close these CCR storage facilities between 2018 and 2024. Ameren Missouri also estimates it will need to make capital expenditures of $300$75 million to $350$125 million from 20182020 through 20222024 to implement its CCR management compliance plan.plan, which includes installation of dry ash handling systems, wastewater treatment facilities, and groundwater monitoring equipment.
Remediation
The Ameren Companies are involved in a number of remediation actions to clean up sites affectedimpacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by federal or state governments as a potentially responsible party at several contaminated sites.
As of December 31, 2017,2019, Ameren Illinois owned or was otherwise responsible forhas remediated the majority of the 44 former MGP sites in Illinois it owned or for which are in various stages of investigation, evaluation, remediation, and closure.it was otherwise responsible. Ameren Illinois estimates it could substantially conclude remediation efforts at the remaining sites by 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders. Costs are subject to annual prudence review by the ICC. As of December 31, 2017,2019, Ameren Illinois estimated the remaining obligation related to these former MGP sites at $175$129 million to $249$213 million. Ameren and Ameren Illinois recorded a liability of $175$129 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.
The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the ultimate actual costs, including unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs and timing of completion may vary substantially from these estimates.
Ameren Missouri participated in the investigation of various sites known as Sauget Area 2 located in Sauget, Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies that former landfills and lagoons at those sites may contain soil and groundwater contamination. In 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation actions recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA-approved cleanup remedies. As of December 31, 2017 and 2016, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.
Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.
NOTE 15 – SUPPLEMENTAL INFORMATION
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of December 31, 2019and2018:
|
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | | December 31, 2018 |
| Ameren | Ameren
Missouri | Ameren
Illinois | | | Ameren | Ameren
Missouri | Ameren
Illinois |
| Cash and cash equivalents | $ | 16 |
| $ | 9 |
| $ | — |
| | | $ | 16 |
| $ | — |
| $ | — |
|
| Restricted cash included in “Other current assets” | 14 |
| 4 |
| 5 |
| | | 13 |
| 4 |
| 6 |
|
| Restricted cash included in “Other assets” | 120 |
| — |
| 120 |
| | | 74 |
| — |
| 74 |
|
| Restricted cash included in “Nuclear decommissioning trust fund” | 26 |
| 26 |
| — |
| | | 4 |
| 4 |
| — |
|
| Total cash, cash equivalents, and restricted cash | $ | 176 |
| $ | 39 |
| $ | 125 |
| | | $ | 107 |
| $ | 8 |
| $ | 80 |
|
Restricted cash included in “Other current assets” primarily represents funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees. Restricted cash included in “Other assets” on Ameren’s and Ameren Missouri Municipal Taxes
The cities of Creve Coeur and Winchester, Missouri, on behalf of themselves and other municipalities in Ameren Missouri’s service area, filedIllinois’ balance sheets primarily represents amounts collected under a class action lawsuit in November 2011 against Ameren Missouricost recovery rider that are restricted for use in the Circuit Courtprocurement of St. Louis County, Missouri. The lawsuit allegesrenewable energy credits and amounts in a trust fund restricted for the use of funding certain asbestos-related claims.
Accounts Receivable
“Accounts receivable – trade” on Ameren’s and Ameren Illinois’ balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At December 31, 2019 and 2018, “Other current liabilities” on Ameren’s and Ameren Missouri failed to collectIllinois’ balance sheets included payables for purchased receivables of $32 million and pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power$33 million, respectively.
For the years ended December 31, 2019, 2018, and interchange sales. In December 2017, the court issued a final order approving a settlement agreement between Ameren MissouriCompanies recorded immaterial bad debt expense.
Inventories
The following table presents the components of inventories for each of the Ameren Companies at December 31, 2019 and the municipalities. The settlement agreement requires Ameren Missouri to make payments representing certain tax receipts to the municipalities during2018:
|
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | | December 31, 2018 |
| | Ameren Missouri | Ameren Illinois | Ameren | | | Ameren Missouri | Ameren Illinois | Ameren |
Fuel(a) | $ | 126 |
| $ | — |
| $ | 126 |
| | | $ | 123 |
| $ | — |
| $ | 123 |
|
| Natural gas stored underground | 6 |
| 57 |
| 63 |
| | | 7 |
| 64 |
| 71 |
|
| Materials, supplies, and other | 241 |
| 64 |
| 305 |
| | | 228 |
| 61 |
| 289 |
|
| Total inventories | $ | 373 |
| $ | 121 |
| $ | 494 |
| | | $ | 358 |
| $ | 125 |
| $ | 483 |
|
| |
| (a) | Consists of coal, oil, and propane. |
Leases
In the first quarter of 2018, in addition2019, we adopted authoritative accounting guidance related to paymentleases, which affected our financial position, but did not materially affect our results of certain future gross receipts taxes.operations or liquidity. The future gross receipts taxes are recoverable from customers.most significant impact for us was the recognition of right-of-use assets and lease liabilities for operating leases, while the accounting for our finance leases remained substantially unchanged. Ameren and Ameren Missouri recordedrecognized right-of-use assets and offsetting lease liabilities of $38 million and $36 million at January 1, 2019, respectively, primarily related to rail car leases. The effect of the adoption was immaterial currentat Ameren Illinois. No adjustment to comparative periods was made. We elected the available practical expedients upon adoption.
Ameren Missouri primarily leases rail cars under operating lease arrangements for the transportation of coal inventory to its energy centers. Although Ameren Missouri has options to renew a portion of these arrangements for up to five years on similar terms, the exercise of these options was not assumed in the recognition of right-of-use assets and lease obligations. For rail car leases, we account for the lease and non-lease components as a single lease component.
The operating lease expense and the cash paid for amounts included in the measurement of operating lease liabilities on their respectiveat Ameren and Ameren Missouri were immaterial for the years ended December 31, 2019, 2018, and 2017.
The following table provides supplemental balance sheetssheet information related to operating leases as of December 31, 2017,2019:
|
| | | | | | | |
| | Ameren | | Ameren Missouri |
| Other assets | $ | 36 |
| | $ | 34 |
|
| Other current liabilities | 7 |
| | 7 |
|
| Other deferred credits and liabilities | 29 |
| | 27 |
|
| Weighted average remaining operating lease term | 5 years |
| | 5 years |
|
Weighted average discount rate(a) | 3.5 | % | | 3.4 | % |
| |
| (a) | As an implicit rate is not readily determinable under most of our lease agreements, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. We use an implicit rate when readily determinable. |
The following table presents remaining maturities of operating lease liabilities as of December 31, 2019:
|
| | | | | | | |
| | Ameren | | Ameren Missouri |
| 2020 | $ | 8 |
| | $ | 8 |
|
| 2021 | 8 |
| | 7 |
|
| 2022 | 7 |
| | 6 |
|
| 2023 | 6 |
| | 6 |
|
| 2024 | 5 |
| | 5 |
|
| Thereafter | 5 |
| | 5 |
|
| Total lease payments | 39 |
| | 37 |
|
| Less imputed interest | 3 |
| | 3 |
|
Total(a) | $ | 36 |
| | $ | 34 |
|
| |
| (a) | The amount of remaining maturities of operating lease liabilities under previous authoritative accounting guidance as of December 31, 2018, is materially consistent with the amount as of December 31, 2019. Maturities of certain financing arrangements, including the Peno Creek and Audrain energy centers' long-term agreements, are no longer required to be disclosed as lease-related maturities. See Note 5 – Long-Term Debt and Equity Financings, for further information on financing arrangements. |
Asset Retirement Obligations
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years ended December 31, 2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | | December 31, 2018 |
| | Ameren Missouri | | Ameren Illinois | | Ameren | | | | Ameren Missouri | | Ameren Illinois | | Ameren | |
| Beginning balance at January 1 | $ | 646 |
| (a) | $ | 4 |
| (b) | $ | 650 |
| (a) | | | $ | 640 |
| | $ | 4 |
| | $ | 644 |
| |
| Liabilities settled | (20 | ) | | — |
| | (20 | ) | | | | (7 | ) | | — |
| | (7 | ) | |
Accretion(c) | 28 |
| | — |
| | 28 |
| | | | 27 |
| | — |
| | 27 |
| |
| Change in estimates | 33 |
| (d) | — |
| | 33 |
| (d) | | | (14 | ) | (e) | — |
| | (14 | ) | (e) |
| Ending balance at December 31 | $ | 687 |
| (a) | $ | 4 |
| (b) | $ | 691 |
| (a) | | | $ | 646 |
| (a) | $ | 4 |
| (b) | $ | 650 |
| (a) |
| |
| (a) | Balance included $53 million and $23 million in “Other current liabilities” on the balance sheet as of December 31, 2019 and 2018, respectively. |
| |
| (b) | Included in “Other deferred credits and liabilities” on the balance sheet. |
| |
| (c) | Ameren Missouri’s accretion expense was deferred as a decrease to regulatory liabilities. |
| |
| (d) | Ameren Missouri changed its fair value estimate primarily due to an increase in the cost estimate for closure of certain CCR storage facilities. |
| |
| (e) | Ameren Missouri changed its fair value estimate primarily due to a reduction in the cost estimate for closure of certain CCR storage facilities. |
Noncontrolling Interests
As of December 31, 2019 and 2018, Ameren’s noncontrolling interests included the preferred stock of Ameren Missouri and Ameren Illinois.
Deferred Compensation
As of December 31, 2019, and 2018, “Other current liabilities’ and “Other deferred credits and liabilities” on Ameren’s balance sheet included deferred compensation obligations of $86 million and $80 million, respectively, recorded at the present value of future benefits to representbe paid.
Excise Taxes
Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the payments madesale or distribution of natural gas and electricity. The following table presents the excise taxes recorded on a gross basis in February“Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income for the years ended December 31, 2019, 2018, underand 2017:
|
| | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | |
| Ameren Missouri | $ | 147 |
| | $ | 164 |
| | $ | 153 |
| |
| Ameren Illinois | 117 |
| | 118 |
| | 112 |
| |
| Ameren | $ | 264 |
| | $ | 282 |
| | $ | 265 |
| |
Allowance for Funds Used During Construction
The following table presents the settlement agreement.average rate that was applied to eligible construction work in progress and the amounts of allowance for funds used during construction capitalized in 2019, 2018, and 2017:
|
| | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | |
| Average rate: | | | | | | |
| Ameren Missouri | 6 | % | | 7 | % | | 7 | % | |
| Ameren Illinois | 5 | % | | 5 | % | | 4 | % | |
| Ameren: | | | | | | |
| Allowance for equity funds used during construction | $ | 28 |
| | $ | 36 |
| | $ | 24 |
| |
| Allowance for borrowed funds used during construction | 20 |
| | 21 |
| | 14 |
| |
| Total Ameren | $ | 48 |
| | $ | 57 |
| | $ | 38 |
| |
| Ameren Missouri: | | | | | | |
| Allowance for equity funds used during construction | $ | 19 |
| | $ | 27 |
| | $ | 21 |
| |
| Allowance for borrowed funds used during construction | 12 |
| | 14 |
| | 10 |
| |
| Total Ameren Missouri | $ | 31 |
| | $ | 41 |
| | $ | 31 |
| |
| Ameren Illinois: | | | | | | |
| Allowance for equity funds used during construction | $ | 9 |
| | $ | 9 |
| | $ | 3 |
| |
| Allowance for borrowed funds used during construction | 8 |
| | 7 |
| | 4 |
| |
| Total Ameren Illinois | $ | 17 |
| | $ | 16 |
| | $ | 7 |
| |
Earnings per Share
Earnings per basic and diluted share are computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of basic and diluted common shares outstanding, respectively, during the applicable period. The weighted-average shares outstanding for earnings per diluted share includes the incremental effects resulting from performance share units, restricted stock units, and the forward sale agreement relating to common stock when the impact would be dilutive, as calculated using the treasury stock method. For information regarding performance share units and restricted stock units, see Note 11 – Stock-based Compensation. For information regarding the forward sale agreement, see Note 5 – Long-term Debt and Equity Financings.
The following table reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2019, 2018, and 2017:
|
| | | | | | | | |
| 2019 | | 2018 | | 2017 |
| Weighted-average Common Shares Outstanding – Basic | 245.6 |
| | 243.8 |
| | 242.6 |
|
| Assumed settlement of performance share units and restricted stock units | 1.4 |
| | 2.0 |
| | 1.6 |
|
| Dilutive effect of forward sale agreement related to common stock | 0.1 |
| | — |
| | — |
|
Weighted-average Common Shares Outstanding – Diluted(a) | 247.1 |
| | 245.8 |
| | 244.2 |
|
| |
| (a) | There were 0 potentially dilutive securities excluded from the earnings per diluted share calculations for the years ended December 31, 2019, 2018, and 2017. |
Supplemental Cash Flow Information
The following table provides noncash financing and investing activity excluded from the statements of cash flows for the years ended December 31, 2019 and 2018. There was no noncash financing or investing activity for the year ended December 31, 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 | | December 31, 2017 |
| Ameren | Ameren Missouri | Ameren Illinois | | Ameren | Ameren Missouri | Ameren Illinois | | Ameren | Ameren Missouri | Ameren Illinois |
| Investing | | | | | | | | | | | |
Exchange of bond investments for the extinguishment of senior unsecured notes(a) | $ | 17 |
| $ | — |
| $ | 17 |
| | $ | — |
| $ | — |
| $ | — |
| | $ | — |
| $ | — |
| $ | — |
|
| Accrued capital expenditures | 333 |
| 140 |
| 163 |
| | 272 |
| 121 |
| 138 |
| | 361 |
| 159 |
| 175 |
|
| Accrued nuclear fuel expenditures | 19 |
| 19 |
| — |
| | 20 |
| 20 |
| — |
| | 10 |
| 10 |
| — |
|
Net realized and unrealized gain – nuclear decommissioning trust fund | 143 |
| 143 |
| — |
| | (38 | ) | (38 | ) | — |
| | 3 |
| 3 |
| — |
|
| Financing | | | | | | | | | | | |
Exchange of bond investments for the extinguishment of senior unsecured notes(a) | $ | (17 | ) | $ | — |
| $ | (17 | ) | | $ | — |
| $ | — |
| $ | — |
| | $ | — |
| $ | — |
| $ | — |
|
| Issuance of common stock for stock-based compensation | 54 |
| — |
| — |
| | 35 |
| — |
| — |
| | — |
| — |
| — |
|
| |
| (a) | See Note 4 – Long-term Debt and Equity Financings for additional information. |
NOTE 15 16 – SEGMENT INFORMATION
Ameren has four4 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 is primarily composedconsists of the aggregated electric transmission businesses of Ameren Illinois and ATXI.ATXI. The category called Other primarily includes Ameren parent company(parent) activities and Ameren Services.
Ameren Missouri has one1 segment. Ameren Illinois has three 3 segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri, Ameren Illinois, and ATXI.
Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, 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. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.
The following tables present revenues,information about the reported revenue and specified items reflected in net income attributable to common shareholders and capital expenditures by segment at Ameren and Ameren Illinois for the years ended December 31, 20172019, 20162018, and 20152017. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.
Ameren
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren | |
| 2019 | | | | | | | | | | | | | | |
| External revenues | $ | 3,212 |
| | $ | 1,487 |
| | $ | 791 |
| | $ | 401 |
| | $ | — |
| | $ | — |
| | $ | 5,891 |
| |
| Intersegment revenues | 31 |
| | 17 |
| | 6 |
| | 63 |
| (a) | — |
| | (98 | ) | | 19 |
| (b) |
| Depreciation and amortization | 556 |
| | 273 |
| | 78 |
| | 84 |
| | 4 |
| | — |
| | 995 |
| |
| Interest income | 26 |
| | 6 |
| | — |
| | 1 |
| | 5 |
| | (5 | ) | | 33 |
| |
| Interest charges | 178 |
| | 71 |
| | 38 |
| | 74 |
| (c) | 25 |
| | (5 | ) | | 381 |
| |
| Income taxes (benefit) | 68 |
| | 45 |
| | 30 |
| | 64 |
| | (25 | ) | | — |
| | 182 |
| |
| Net income (loss) attributable to Ameren common shareholders | 426 |
| | 146 |
| | 84 |
| | 185 |
| | (13 | ) | | — |
| | 828 |
| |
| Capital expenditures | 1,076 |
| | 518 |
| | 318 |
| | 528 |
| | 3 |
| | (32 | ) | (d) | 2,411 |
| |
| 2018 | | | | | | | | | | | | | | |
| External revenues | $ | 3,555 |
| | $ | 1,544 |
| | $ | 814 |
| | $ | 378 |
| | $ | — |
| | $ | — |
| | $ | 6,291 |
| |
| Intersegment revenues | 34 |
| | 3 |
| | 1 |
| | 55 |
| (a) | — |
| | (93 | ) | | — |
| |
| Depreciation and amortization | 550 |
| | 259 |
| | 65 |
| | 77 |
| | 4 |
| | — |
| | 955 |
| |
| Interest income | 28 |
| | 6 |
| | — |
| | — |
| | 4 |
| | (5 | ) | | 33 |
| |
| Interest charges | 200 |
| | 73 |
| | 38 |
| | 75 |
| (c) | 19 |
| | (4 | ) | | 401 |
| |
| Income taxes (benefit) | 124 |
| | 41 |
| | 25 |
| | 56 |
| | (9 | ) | | — |
| | 237 |
| |
| Net income (loss) attributable to Ameren common shareholders | 478 |
| | 136 |
| | 70 |
| | 164 |
| | (33 | ) | | — |
| | 815 |
| |
| Capital expenditures | 914 |
| | 503 |
| | 311 |
| | 562 |
| | 5 |
| | (9 | ) | | 2,286 |
| |
| 2017 | | | | | | | | | | | | | | |
| External revenues | $ | 3,488 |
| | $ | 1,564 |
| | $ | 742 |
| | $ | 382 |
| | $ | (2 | ) | | $ | — |
| | $ | 6,174 |
| |
| Intersegment revenues | 49 |
| | 4 |
| | 1 |
| | 44 |
| (a) | — |
| | (98 | ) | | — |
| |
| Depreciation and amortization | 533 |
| | 239 |
| | 59 |
| | 60 |
| | 5 |
| | — |
| | 896 |
| |
| Interest income | 27 |
| | 7 |
| | — |
| | — |
| | 11 |
| | (11 | ) | | 34 |
| |
| Interest charges | 207 |
| | 73 |
| | 36 |
| | 67 |
| (c) | 19 |
| | (11 | ) | | 391 |
| |
| Income taxes | 254 |
| | 83 |
| | 36 |
| | 90 |
| | 113 |
| | — |
| | 576 |
| |
| Net income (loss) attributable to Ameren common shareholders | 323 |
| | 131 |
| | 60 |
| | 140 |
| | (131 | ) | | — |
| | 523 |
| |
| Capital expenditures | 773 |
| | 476 |
| | 245 |
| | 644 |
| | 1 |
| | (7 | ) | | 2,132 |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Consolidated |
| 2017 | | | | | | | | | | | | | |
| External revenues | $ | 3,490 |
| | $ | 1,565 |
| | $ | 742 |
| | $ | 382 |
| | $ | (2 | ) | | $ | — |
| | $ | 6,177 |
|
| Intersegment revenues | 49 |
| | 4 |
| | 1 |
| | 44 |
| (a) | — |
| | (98 | ) | | — |
|
| Depreciation and amortization | 533 |
| | 239 |
| | 59 |
| | 60 |
| | 5 |
| | — |
| | 896 |
|
| Interest income | 27 |
| | 7 |
| | — |
| | — |
| | 11 |
| | (11 | ) | | 34 |
|
| Interest charges | 207 |
| | 73 |
| | 36 |
| | 67 |
| (b) | 19 |
| | (11 | ) | | 391 |
|
| Income taxes | 254 |
| | 83 |
| | 36 |
| | 90 |
| | 113 |
| | — |
| | 576 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 323 |
| | 131 |
| | 60 |
| | 140 |
| | (131 | ) | | — |
| | 523 |
|
| Capital expenditures | 773 |
| | 476 |
| | 245 |
| | 644 |
| | 1 |
| | (7 | ) | | 2,132 |
|
| 2016 | | | | | | | | | | | | | |
| External revenues | $ | 3,469 |
| | $ | 1,545 |
| | $ | 753 |
| | $ | 309 |
| | $ | — |
| | $ | — |
| | $ | 6,076 |
|
| Intersegment revenues | 54 |
| | 4 |
| | 1 |
| | 46 |
| (a) | — |
| | (105 | ) | | — |
|
| Depreciation and amortization | 514 |
| | 226 |
| | 55 |
| | 43 |
| | 7 |
| | — |
| | 845 |
|
| Interest income | 28 |
| | 11 |
| | — |
| | 1 |
| | 11 |
| | (11 | ) | | 40 |
|
| Interest charges | 211 |
| | 72 |
| | 34 |
| | 58 |
| (b) | 18 |
| | (11 | ) | | 382 |
|
| Income taxes | 216 |
| | 78 |
| | 39 |
| | 74 |
| | (25 | ) | | — |
| | 382 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 357 |
| | 126 |
| | 59 |
| | 117 |
| | (6 | ) | | — |
| | 653 |
|
| Capital expenditures | 738 |
| | 470 |
| | 181 |
| | 689 |
| | 4 |
| | (6 | ) | | 2,076 |
|
| 2015 | | | | | | | | | | | | | |
| External revenues | $ | 3,566 |
| | $ | 1,529 |
| | $ | 782 |
| | $ | 219 |
| | $ | 2 |
| | $ | — |
| | $ | 6,098 |
|
| Intersegment revenues | 43 |
| | 3 |
| | 1 |
| | 40 |
| (a) | — |
| | (87 | ) | | — |
|
| Depreciation and amortization | 492 |
| | 212 |
| | 52 |
| | 33 |
| | 7 |
| | — |
| | 796 |
|
| Interest income | 28 |
| | 12 |
| | — |
| | — |
| | 7 |
| | (6 | ) | | 41 |
|
| Interest charges | 219 |
| | 71 |
| | 35 |
| | 35 |
| (b) | 1 |
| | (6 | ) | | 355 |
|
| Income taxes | 209 |
| | 71 |
| | 24 |
| | 51 |
| | 8 |
| | — |
| | 363 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 352 |
| | 123 |
| | 37 |
| | 83 |
| | (16 | ) | | — |
| | 579 |
|
| Capital expenditures | 622 |
| | 491 |
| | 133 |
| | 669 |
| | 2 |
| | — |
| | 1,917 |
|
| |
| (a) | Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
| |
| (b) | Intersegment revenues at Ameren include $14 million and $5 million of revenue from Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. Under authoritative accounting guidance for rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation. See Note 13 – Related-party Transactions for additional information. |
| |
| (c) | Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent). |
| |
| (d) | Intersegment capital expenditure eliminations include $24 million of eliminations for the year ended December 31, 2019 for a software licensing agreement between Ameren Illinois and Ameren Missouri. See Note 13 – Related-party Transactions for additional information. |
Ameren Illinois
| | | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Consolidated | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois |
| 2019 | | | | | | | | | | |
| External revenues | | $ | 1,504 |
| | $ | 797 |
| | $ | 226 |
| | $ | — |
| | $ | 2,527 |
|
| Intersegment revenues | | — |
| | — |
| | 62 |
| (a) | (62 | ) | | — |
|
| Depreciation and amortization | | 273 |
| | 78 |
| | 55 |
| | — |
| | 406 |
|
| Interest income | | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
| Interest charges | | 71 |
| | 38 |
| | 38 |
| | — |
| | 147 |
|
| Income taxes | | 45 |
| | 30 |
| | 35 |
| | — |
| | 110 |
|
| Net income available to common shareholder | | 146 |
| | 84 |
| | 113 |
| | — |
| | 343 |
|
| Capital expenditures | | 518 |
| | 318 |
| | 372 |
| | — |
| | 1,208 |
|
| 2018 | | | | | | | | | | |
| External revenues | | $ | 1,547 |
| | $ | 815 |
| | $ | 214 |
| | $ | — |
| | $ | 2,576 |
|
| Intersegment revenues | | — |
| | — |
| | 53 |
| (a) | (53 | ) | | — |
|
| Depreciation and amortization | | 259 |
| | 65 |
| | 50 |
| | — |
| | 374 |
|
| Interest income | | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
| Interest charges | | 73 |
| | 38 |
| | 38 |
| | — |
| | 149 |
|
| Income taxes | | 41 |
| | 25 |
| | 32 |
| | — |
| | 98 |
|
| Net income available to common shareholder | | 136 |
| | 70 |
| | 98 |
| | — |
| | 304 |
|
| Capital expenditures | | 503 |
| | 311 |
| | 444 |
| | — |
| | 1,258 |
|
| 2017 | | | | | | | | | | | | | | | | | | | |
| External revenues | $ | 1,569 |
| | $ | 743 |
| | $ | 216 |
| | $ | — |
| | $ | 2,528 |
| | $ | 1,568 |
| | $ | 743 |
| | $ | 216 |
| | $ | — |
| | $ | 2,527 |
|
| Intersegment revenues | — |
| | — |
| | 42 |
| (a) | (42 | ) | | — |
| | — |
| | — |
| | 42 |
| (a) | (42 | ) | | — |
|
| Depreciation and amortization | 239 |
| | 59 |
| | 43 |
| | — |
| | 341 |
| | 239 |
| | 59 |
| | 43 |
| | — |
| | 341 |
|
| Interest income | 7 |
| | — |
| | — |
| | — |
| | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Interest charges | 73 |
| | 36 |
| | 35 |
| | — |
| | 144 |
| | 73 |
| | 36 |
| | 35 |
| | — |
| | 144 |
|
| Income taxes | 83 |
| | 36 |
| | 47 |
| | — |
| | 166 |
| | 83 |
| | 36 |
| | 47 |
| | — |
| | 166 |
|
| Net income available to common shareholder | 131 |
| | 60 |
| | 77 |
| | — |
| | 268 |
| | 131 |
| | 60 |
| | 77 |
| | — |
| | 268 |
|
| Capital expenditures | 476 |
| | 245 |
| | 355 |
| | — |
| | 1,076 |
| | 476 |
| | 245 |
| | 355 |
| | — |
| | 1,076 |
|
| 2016 | | | | | | | | | | | |
| External revenues | $ | 1,549 |
| | $ | 754 |
| | $ | 187 |
| | $ | — |
| | $ | 2,490 |
| | |
| Intersegment revenues | — |
| | — |
| | 45 |
| (a) | (45 | ) | | — |
| | |
| Depreciation and amortization | 226 |
| | 55 |
| | 38 |
| | — |
| | 319 |
| | |
| Interest income | 11 |
| | — |
| | 1 |
| | — |
| | 12 |
| | |
| Interest charges | 72 |
| | 34 |
| | 34 |
| | — |
| | 140 |
| | |
| Income taxes | 78 |
| | 39 |
| | 41 |
| | — |
| | 158 |
| | |
| Net income available to common shareholder | 126 |
| | 59 |
| | 67 |
| | — |
| | 252 |
| | |
| Capital expenditures | 470 |
| | 181 |
| | 273 |
| | — |
| | 924 |
| | |
| 2015 | | | | | | | | | | | |
| External revenues | $ | 1,532 |
| | $ | 783 |
| | $ | 151 |
| | $ | — |
| | $ | 2,466 |
| | |
| Intersegment revenues | — |
| | — |
| | 38 |
| (a) | (38 | ) | | — |
| | |
| Depreciation and amortization | 212 |
| | 52 |
| | 31 |
| | — |
| | 295 |
| | |
| Interest income | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | |
| Interest charges | 71 |
| | 35 |
| | 25 |
| | — |
| | 131 |
| | |
| Income taxes | 71 |
| | 24 |
| | 32 |
| | — |
| | 127 |
| | |
| Net income available to common shareholder | 123 |
| | 37 |
| | 54 |
| | — |
| | 214 |
| | |
| Capital expenditures | 491 |
| | 133 |
| | 294 |
| | — |
| | 918 |
| | |
| |
| (a) | Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the years ended December 31, 2019, 2018, and 2017. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren | |
| 2019 | | | | | | | | | | | | | | |
| Residential | $ | 1,403 |
| | $ | 848 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,251 |
| |
| Commercial | 1,157 |
| | 497 |
| | — |
| | — |
| | — |
| | — |
| | 1,654 |
| |
| Industrial | 278 |
| | 127 |
| | — |
| | — |
| | — |
| | — |
| | 405 |
| |
| Other | 271 |
| | 32 |
| (a) | — |
| | 464 |
| | — |
| | (96 | ) | | 671 |
| |
| Total electric revenues | $ | 3,109 |
| | $ | 1,504 |
| | $ | — |
| | $ | 464 |
| | $ | — |
| | $ | (96 | ) | | $ | 4,981 |
| |
| Residential | $ | 81 |
| | $ | — |
| | $ | 570 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 651 |
| |
| Commercial | 34 |
| | — |
| | 154 |
| | — |
| | — |
| | — |
| | 188 |
| |
| Industrial | 4 |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| | 17 |
| |
| Other | 15 |
| | — |
| | 60 |
| (a) | — |
| | — |
| | (2 | ) | | 73 |
| |
| Total gas revenues | $ | 134 |
| | $ | — |
| | $ | 797 |
| | $ | — |
| | $ | — |
| | $ | (2 | ) | | $ | 929 |
| |
Total revenues(b) | $ | 3,243 |
| | $ | 1,504 |
| | $ | 797 |
| | $ | 464 |
| | $ | — |
| | $ | (98 | ) | | $ | 5,910 |
| |
| 2018 | | | | | | | | | | | | | | |
| Residential | $ | 1,560 |
| | $ | 867 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,427 |
| |
| Commercial | 1,271 |
| | 511 |
| | — |
| | — |
| | — |
| | — |
| | 1,782 |
| |
| Industrial | 312 |
| | 130 |
| | — |
| | — |
| | — |
| | — |
| | 442 |
| |
| Other | 308 |
| (c) | 39 |
| | — |
| | 433 |
| | — |
| | (92 | ) | | 688 |
| (c) |
| Total electric revenues | $ | 3,451 |
| | $ | 1,547 |
| | $ | — |
| | $ | 433 |
| | $ | — |
| | $ | (92 | ) | | $ | 5,339 |
| |
| Residential | $ | 90 |
| | $ | — |
| | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 671 |
| |
| Commercial | 37 |
| | — |
| | 159 |
| | — |
| | — |
| | — |
| | 196 |
| |
| Industrial | 4 |
| | — |
| | 17 |
| | — |
| | — |
| | — |
| | 21 |
| |
| Other | 7 |
| | — |
| | 58 |
| | — |
| | — |
| | (1 | ) | | 64 |
| |
| Total gas revenues | $ | 138 |
| | $ | — |
| | $ | 815 |
| | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | 952 |
| |
Total revenues(b) | $ | 3,589 |
| | $ | 1,547 |
| | $ | 815 |
| | $ | 433 |
| | $ | — |
| | $ | (93 | ) | | $ | 6,291 |
| |
| 2017 | | | | | | | | | | | | | | |
| Residential | $ | 1,417 |
| | $ | 870 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,287 |
| |
| Commercial | 1,208 |
| | 527 |
| | — |
| | — |
| | — |
| | — |
| | 1,735 |
| |
| Industrial | 305 |
| | 113 |
| | — |
| | — |
| | — |
| | — |
| | 418 |
| |
| Other | 481 |
| | 58 |
| | — |
| | 426 |
| | (2 | ) | | (96 | ) | | 867 |
| |
| Total electric revenues | $ | 3,411 |
| | $ | 1,568 |
| | $ | — |
| | $ | 426 |
| | $ | (2 | ) | | $ | (96 | ) | | $ | 5,307 |
| |
| Residential | $ | 77 |
| | $ | — |
| | $ | 531 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 608 |
| |
| Commercial | 31 |
| | — |
| | 146 |
| | — |
| | — |
| | — |
| | 177 |
| |
| Industrial | 4 |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | 16 |
| |
| Other | 14 |
| | — |
| | 54 |
| | — |
| | — |
| | (2 | ) | | 66 |
| |
| Total gas revenues | $ | 126 |
| | $ | — |
| | $ | 743 |
| | $ | — |
| | $ | — |
| | $ | (2 | ) | | $ | 867 |
| |
Total revenues(b) | $ | 3,537 |
| | $ | 1,568 |
| | $ | 743 |
| | $ | 426 |
| | $ | (2 | ) | | $ | (98 | ) | | $ | 6,174 |
| |
| |
| (a) | Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information. |
(b)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the years ended December 31, 2019, 2018, and 2017: |
| | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Ameren |
| 2019 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 35 |
| | $ | (74 | ) | | $ | — |
| | $ | (31 | ) | | $ | (70 | ) |
| Other revenues not from contracts with customers | 19 |
| | 7 |
| | 2 |
| | — |
| | 28 |
|
| 2018 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (8 | ) | | $ | (3 | ) | | $ | (23 | ) | | $ | (25 | ) | | $ | (59 | ) |
| Other revenues not from contracts with customers | 24 |
| | 16 |
| | 2 |
| | — |
| | 42 |
|
| 2017 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (28 | ) | | $ | (5 | ) | | $ | 5 |
| | $ | 13 |
| | $ | (15 | ) |
| Other revenues not from contracts with customers | 15 |
| | 6 |
| | 2 |
| | — |
| | 23 |
|
| |
| (c) | Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates to be refunded related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information. |
Ameren Illinois
|
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| 2019 | | | | | | | | | | |
| Residential | $ | 848 |
| | $ | 570 |
| | $ | — |
| | $ | — |
| | $ | 1,418 |
| |
| Commercial | 497 |
| | 154 |
| | — |
| | — |
| | 651 |
| |
| Industrial | 127 |
| | 13 |
| | — |
| | — |
| | 140 |
| |
| Other | 32 |
| (a) | 60 |
| (a) | 288 |
| | (62 | ) | | 318 |
| |
Total revenues(b) | $ | 1,504 |
| | $ | 797 |
| | $ | 288 |
| | $ | (62 | ) | | $ | 2,527 |
| |
| 2018 | | | | | | | | | | |
| Residential | $ | 867 |
| | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | 1,448 |
| |
| Commercial | 511 |
| | 159 |
| | — |
| | — |
| | 670 |
| |
| Industrial | 130 |
| | 17 |
| | — |
| | — |
| | 147 |
| |
| Other | 39 |
| | 58 |
| | 267 |
| | (53 | ) | | 311 |
| |
Total revenues(b) | $ | 1,547 |
| | $ | 815 |
| | $ | 267 |
| | $ | (53 | ) | | $ | 2,576 |
| |
| 2017 | | | | | | | | | | |
| Residential | $ | 870 |
| | $ | 531 |
| | $ | — |
| | $ | — |
| | $ | 1,401 |
| |
| Commercial | 527 |
| | 146 |
| | — |
| | — |
| | 673 |
| |
| Industrial | 113 |
| | 12 |
| | — |
| | — |
| | 125 |
| |
| Other | 58 |
| | 54 |
| | 258 |
| | (42 | ) | | 328 |
| |
Total revenues(b) | $ | 1,568 |
| | $ | 743 |
| | $ | 258 |
| | $ | (42 | ) | | $ | 2,527 |
| |
| |
| (a) | Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information. |
| |
| (b) | The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the years ended December 31, 2019, 2018, and 2017: |
|
| | | | | | | | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois |
| 2019 | | | | | | | |
| Revenues from alternative revenue programs | $ | (74 | ) | | $ | — |
| | $ | (33 | ) | | $ | (107 | ) |
| Other revenues not from contracts with customers | 7 |
| | 2 |
| | — |
| | 9 |
|
| 2018 | | | | | | | |
| Revenues from alternative revenue programs | $ | (3 | ) | | $ | (23 | ) | | $ | (25 | ) | | $ | (51 | ) |
| Other revenues not from contracts with customers | 16 |
| | 2 |
| | — |
| | 18 |
|
| 2017 | | | | | | | |
| Revenues from alternative revenue programs | $ | (5 | ) | | $ | 5 |
| | $ | 9 |
| | $ | 9 |
|
| Other revenues not from contracts with customers | 6 |
| | 2 |
| | — |
| | 8 |
|
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2019 | | | 2018 | |
| Quarter ended | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 |
| | June 30 |
| | September 30 | | December 31 | |
| Operating revenues | $ | 1,556 |
| | $ | 1,379 |
| | $ | 1,659 |
| | $ | 1,316 |
| | | $ | 1,585 |
| | $ | 1,563 |
| | $ | 1,724 |
| | $ | 1,419 |
| |
| Operating income | 288 |
| | 280 |
| | 520 |
| | 179 |
| | | 273 |
| | 385 |
| | 533 |
| | 166 |
| |
| Net income | 193 |
| | 180 |
| | 366 |
| | 95 |
| | | 153 |
| | 240 |
| | 359 |
| | 69 |
| |
| Net income attributable to Ameren common shareholders | $ | 191 |
| | $ | 179 |
| | $ | 364 |
| | $ | 94 |
| | | $ | 151 |
| | $ | 239 |
| | $ | 357 |
| | $ | 68 |
| |
| Earnings per common share – basic | $ | 0.78 |
| | $ | 0.73 |
| | $ | 1.48 |
| | $ | 0.38 |
| | | $ | 0.62 |
| | $ | 0.98 |
| | $ | 1.46 |
| | $ | 0.28 |
| |
| Earnings per common share – diluted | $ | 0.78 |
| | $ | 0.72 |
| | $ | 1.47 |
| | $ | 0.38 |
| | | $ | 0.62 |
| | $ | 0.97 |
| | $ | 1.45 |
| | $ | 0.28 |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2017 | | | 2016 |
| Quarter ended | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 |
| Operating revenues | $ | 1,514 |
| | $ | 1,538 |
| | $ | 1,723 |
| | $ | 1,402 |
| | | $ | 1,434 |
| | $ | 1,427 |
| | $ | 1,859 |
| | $ | 1,356 |
|
| Operating income | 254 |
| | 398 |
| | 581 |
| | 225 |
| | | 220 |
| | 325 |
| | 691 |
| | 145 |
|
| Net income (loss) | 104 |
| | 194 |
| | 290 |
| | (59 | ) | (a) | | 107 |
| | 148 |
| | 371 |
| | 33 |
|
| Net income (loss) attributable to Ameren common shareholders | $ | 102 |
| | $ | 193 |
| | $ | 288 |
| | $ | (60 | ) | | | $ | 105 |
| | $ | 147 |
| | $ | 369 |
| | $ | 32 |
|
| Earnings (loss) per common share – basic | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.19 |
| | $ | (0.24 | ) | | | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
|
Earnings (loss) per common share – diluted(b) | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.18 |
| | $ | (0.24 | ) | | | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
|
| |
(a)
| Includes an increase to income tax expense of $154 million recorded in 2017 as a result of the TCJA. |
| |
(b) | The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is because of the effects of rounding and the changes in the number of weighted-average diluted shares outstanding each period. |
|
| | | | | | | | | | | | | | | | |
Ameren Missouri Quarter ended | | Operating Revenues | | Operating Income | | Net Income (Loss) | | Net Income (Loss) Available to Common Shareholder |
| March 31, 2019 | | $ | 758 |
| | $ | 79 |
| | $ | 40 |
| | $ | 39 |
|
| March 31, 2018 | | 792 |
| | 90 |
| | 39 |
| | 38 |
|
| June 30, 2019 | | 798 |
| | 152 |
| | 108 |
| | 107 |
|
| June 30, 2018 | | 955 |
| | 258 |
| | 169 |
| | 168 |
|
| September 30, 2019 | | 1,059 |
| | 381 |
| | 301 |
| | 300 |
|
| September 30, 2018 | | 1,129 |
| | 394 |
| | 295 |
| | 294 |
|
| December 31, 2019 | | 628 |
| | 5 |
| | (20 | ) | | (20 | ) |
| December 31, 2018 | | 713 |
| | 7 |
| | (22 | ) | | (22 | ) |
|
| | | | | | | | | | | | | | | | |
Ameren Missouri Quarter ended | | Operating Revenues | | Operating Income | | Net Income (Loss) | | Net Income (Loss) Available to Common Shareholder |
| March 31, 2017 | | $ | 790 |
| | $ | 53 |
| | $ | 6 |
| | $ | 5 |
|
| March 31, 2016 | | 741 |
| | 63 |
| | 15 |
| | 14 |
|
| June 30, 2017 | | 935 |
| | 237 |
| | 121 |
| | 120 |
|
| June 30, 2016 | | 867 |
| | 197 |
| | 93 |
| | 92 |
|
| September 30, 2017 | | 1,115 |
| | 417 |
| | 235 |
| | 234 |
|
| September 30, 2016 | | 1,165 |
| | 431 |
| | 242 |
| | 241 |
|
| December 31, 2017 | | 699 |
| | 40 |
| | (36 | ) | (a) | (36 | ) |
| December 31, 2016 | | 750 |
| | 54 |
| | 10 |
| | 10 |
|
|
| | | | | | | | | | | | | | | | |
Ameren Illinois Quarter ended | | Operating Revenues | | Operating Income | | Net Income | | Net Income Available to Common Shareholder |
| March 31, 2019 | | $ | 762 |
| | $ | 186 |
| | $ | 121 |
| | $ | 120 |
|
| March 31, 2018 | | 760 |
| | 159 |
| | 96 |
| | 95 |
|
| June 30, 2019 | | 547 |
| | 104 |
| | 63 |
| | 62 |
|
| June 30, 2018 | | 578 |
| | 105 |
| | 63 |
| | 62 |
|
| September 30, 2019 | | 564 |
| | 110 |
| | 65 |
| | 65 |
|
| September 30, 2018 | | 564 |
| | 113 |
| | 63 |
| | 63 |
|
| December 31, 2019 | | 654 |
| | 150 |
| | 97 |
| | 96 |
|
| December 31, 2018 | | 674 |
| | 135 |
| | 85 |
| | 84 |
|
| |
(a) | Includes an increase to income tax expense of $32 million recorded in 2017 as a result of the TCJA. |
|
| | | | | | | | | | | | | | | | |
Ameren Illinois Quarter ended(a) | | Operating Revenues | | Operating Income | | Net Income | | Net Income Available to Common Shareholder |
| March 31, 2017 | | $ | 703 |
| | $ | 172 |
| | $ | 80 |
| | $ | 79 |
|
| March 31, 2016 | | 677 |
| | 133 |
| | 60 |
| | 59 |
|
| June 30, 2017 | | 576 |
| | 130 |
| | 58 |
| | 57 |
|
| June 30, 2016 | | 542 |
| | 107 |
| | 46 |
| | 45 |
|
| September 30, 2017 | | 575 |
| | 128 |
| | 55 |
| | 55 |
|
| September 30, 2016 | | 676 |
| | 230 |
| | 119 |
| | 119 |
|
| December 31, 2017 | | 674 |
| | 150 |
| | 78 |
| | 77 |
|
| December 31, 2016 | | 595 |
| | 74 |
| | 30 |
| | 29 |
|
| |
(a) | In 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed the method it used to recognize its interim-period revenue. Ameren Illinois now recognizes revenue consistent with the timing of incurred electric distribution recoverable costs, and it recognizes revenue associated with the expected return on its rate base ratably over the year. As a result of this change in recognition of the interim period revenue for the IEIMA formula rate framework, as modified by the FEJA, Ameren Illinois incurred quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first, second, and fourth quarters and a decrease to earnings in the third quarter. The change in interim period revenue recognition did not affect 2017 annual earnings. |
| |
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| |
| ITEM 9A. | CONTROLS AND PROCEDURES |
| |
| (a) | Evaluation of Disclosure Controls and Procedures |
As of December 31, 2017,2019, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and the 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 on those evaluations, as of December 31, 2017,2019, the principal executive officer and the principal financial officer of each of the Ameren Companies 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 that 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) | Management’s Report on Internal Control over Financial Reporting |
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision of and with the participation of management, including the principal executive officer and the principal financial officer, an evaluation was conducted of the effectiveness of each of the Ameren Companies’
internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). After making that evaluation, management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2017.2019. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2017,2019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of Ameren Missouri’s or Ameren Illinois’ (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over
financial reporting. Management’s report for each of the Subsidiary Registrants is not subject to attestation by an independent registered public accounting firm.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that internal controls might become inadequate because of changes in conditions, and to the risk that the degree of compliance with the policies or procedures might deteriorate.
| |
| (c) | Change in Internal Control |
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.
| |
| ITEM 9B. | OTHER INFORMATION |
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 20172019 that has not previously been reported on an SEC Form 8-K.
PART III
| |
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE |
Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and to each of Ameren Missouri’s and Ameren Illinois’ definitive information statements: “Information Concerning Nominees to the Board of Directors,” “Section“Delinquent Section 16(a) Beneficial Ownership Reporting Compliance,Reports,” “Corporate Governance” and “Board Structure.”
Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Executive Officers of the Registrants”“Information about our Executive Officers” in Part I of this report.
Ameren Missouri and Ameren Illinois do not have separately designated standing audit committees, but instead use Ameren’s audit and risk committee to perform such committee functions for their boards of directors. These companies do not have securities listed on the NYSE and therefore are not subject to the NYSE listing standards. Walter J. GalvinEdward Coleman serves as chairman of Ameren’s audit and risk committee and Catherine S. Brune, J. Edward Coleman,Ward H. Dickson, Noelle K. Eder, and Ellen M. FitzsimmonsCraig S. Ivey serve as members. The board of directors of Ameren has determined that Walter J. Galvin and J. Edward Coleman and Ward H. Dickson each qualify as an audit committee financial expert and that each is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of Ameren Missouri and Ameren Illinois use the nominating and corporate governance committee of Ameren’s board of directors to perform such committee functions. This committee is responsible for the nomination of directors and for corporate governance practices. Ameren’s nominating and corporate governance committee will consider director nominations from shareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s website: www.ameren.com.www.amereninvestors.com. To encourage ethical conduct in its financial management and reporting, Ameren has adopted a code of ethics that applies to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the controller, and the treasurer of each of the Ameren Companies. Ameren has also adopted a code of business conduct that applies to the directors, officers, and employees of the Ameren Companies. It is referred to as the Principles of Business Conduct. The Ameren Companies make available free of charge through Ameren’s website (www.ameren.com)(www.amereninvestors.com) the Code of Ethics and the Principles of Business Conduct. Any amendment to the Code of Ethics or the Principles of Business Conduct and any waiver from a provision of the Code of Ethics or the Principles of Business Conduct as it relates to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the controller, or the treasurer of each of the Ameren Companies will be posted on Ameren’s website within four business days following the date of the amendment or waiver. | |
| ITEM 11. | EXECUTIVE COMPENSATION |
Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and to each of Ameren
Missouri’s and Ameren Illinois’ definitive information statements: “Executive Compensation”Compensation Matters” and “Human Resources Committee Interlocks and Insider Participation.”
| |
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Equity Compensation Plan Information
The following table presents information as of December 31, 2017,2019, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans.plans:
| | Plan Category | | Column A Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights(a) | | Column B Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Column C Number of Securities Remaining Available for Future Issuance Equity Compensation Plans (excluding securities reflected in Column A) | | Column A Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights(a) | | Column B Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Column C Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in Column A) |
Equity compensation plans approved by security holders(b) | | 1,834,043 |
| | (c) |
| | 4,893,953 |
| | 1,500,803 |
| | (c) |
| | 3,081,062 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 1,834,043 |
| | (c) |
| | 4,893,953 |
| | 1,500,803 |
| | (c) |
| | 3,081,062 |
|
| |
| (a) | PursuantOf the securities to grants of performance share units (PSUs) under the 2014 Incentive Plan, 1,767,462be issued, 1,108,794 of the securities represent the target number of PSUs granted but not vested (includingoutstanding performance share units (PSUs) and 313,396 of the securities represent the number of outstanding restricted stock units (RSUs), both including accrued and reinvested dividends) as of December 31, 2017 (including outstanding awards under the 2014 Incentive Plan as of December 31, 2017).dividends. The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level, depending upon the achievement of total shareholder returnTSR objectives established for such awards. For additional information about the PSUs and RSUs, including payout calculations, see “Compensation Discussion and Analysis – Long-Term Incentives: Performance Share Unit Program (“PSUP”)”Incentive Compensation” in Ameren’s definitive proxy statement for its 20182020 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. Also, 66,581The remaining 78,613 of the securities represent shares that may be issued as of December 31, 2017, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for membersMembers of the boardBoard of directors.Directors. |
| |
| (b) | Consists of the 2014 Omnibus Incentive Compensation Plan. |
| |
| (c) | EarnedNo cash consideration is received when shares are distributed for earned PSUs, RSUs, and deferred compensation stock units are paid in shares of Ameren common stock on a one-for-one basis.director awards. Accordingly, the PSUs and deferred compensation stock units do not have athere is no weighted-average exercise price. |
Ameren Missouri and Ameren Illinois do not have separate equity compensation plans.
Security Ownership of Certain Beneficial Owners and Management
The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Security Ownership.”
| |
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
Information required by Items 404 and 407(a) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20182020 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and to each of Ameren Missouri’s and Ameren Illinois’ definitive information statements: “Policy and Procedures With Respect to Related“Related Person Transactions”Transactions Policy” and “Director Independence.”
| |
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of Ameren Missouri and Ameren Illinois for their 20182020 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference. Specifically, reference is made to the
following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Independent“Selection of Independent Registered Public Accounting Firm.”
PART IV
| |
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
|
| |
| | |
| | Page No. |
| (a)(1) Financial Statements | |
| Ameren | |
| Report of Independent Registered Public Accounting Firm | |
Consolidated Statement of Income – Years Ended December 31, 2017, 2016, and 2015 | |
Consolidated Statement of Comprehensive Income – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Consolidated Balance Sheet – December 31, 20172019 and 20162018 | |
Consolidated Statement of Cash Flows – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
| Ameren Missouri | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Balance Sheet – December 31, 20172019 and 20162018 | |
Statement of Cash Flows – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
| Ameren Illinois | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Balance Sheet – December 31, 20172019 and 20162018 | |
Statement of Cash Flows – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
| | |
| (a)(2) Financial Statement Schedules | |
| Schedule I | |
| Condensed Financial Information of Parent – Ameren: | |
Condensed Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Condensed Balance Sheet – December 31, 20172019 and 20162018 | |
Condensed Statement of Cash Flows – Years Ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
| Schedule II | |
| Ameren | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
| Ameren Missouri | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
| Ameren Illinois | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016,2019, 2018, and 20152017 | |
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
|
| | | |
| | | | |
| (a)(3) | | Exhibits – reference is made to the Exhibit Index | |
| (b) | | Exhibit Index | |
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2019, 2018, and 2017 |
| (In millions) | 2019 | | 2018 | | 2017 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
|
| Operating expenses | 15 |
| | 11 |
| | 15 |
|
| Operating loss | (15 | ) | | (11 | ) | | (15 | ) |
| Equity in earnings of subsidiaries | 850 |
| | 857 |
| | 659 |
|
| Interest income from affiliates | 5 |
| | 3 |
| | 9 |
|
| Total other income (expense), net | (2 | ) | | (12 | ) | | 2 |
|
| Interest charges | 39 |
| | 34 |
| | 31 |
|
| Income tax (benefit) | (29 | ) | | (12 | ) | | 101 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 828 |
| | $ | 815 |
| | $ | 523 |
|
| | | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 828 |
| | $ | 815 |
| | $ | 523 |
|
| Other Comprehensive Income (Loss), Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $1, $(1), and $3, respectively | 5 |
| | (4 | ) | | 5 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 833 |
| | $ | 811 |
| | $ | 528 |
|
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015 |
| (In millions) | 2017 | | 2016 | | 2015 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
|
| Operating expenses | 13 |
| | 14 |
| | 14 |
|
| Operating loss | (13 | ) | | (14 | ) | | (14 | ) |
| Equity in earnings of subsidiaries | 659 |
| | 663 |
| | 600 |
|
| Interest income from affiliates | 9 |
| | 10 |
| | 6 |
|
| Total other expense, net | — |
| | (5 | ) | | (5 | ) |
| Interest charges | 31 |
| | 28 |
| | 3 |
|
| Income tax (benefit) | 101 |
| | (27 | ) | | 5 |
|
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | 523 |
| | 653 |
| | 579 |
|
| Net Income Attributable to Ameren Common Shareholders – Discontinued Operations | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | |
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | $ | 523 |
| | $ | 653 |
| | $ | 579 |
|
| Other Comprehensive Income, Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $3, respectively | 5 |
| | (20 | ) | | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 528 |
| | 633 |
| | 585 |
|
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
|
| | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions) | December 31, 2019 | | December 31, 2018 |
| Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Advances to money pool | 102 |
| | 76 |
|
| Accounts receivable – affiliates | 73 |
| | 43 |
|
| Miscellaneous accounts and notes receivable | 4 |
| | 2 |
|
| Other current assets | 3 |
| | 2 |
|
| Total current assets | 182 |
| | 123 |
|
| Investments in subsidiaries | 9,108 |
| | 8,559 |
|
| Note receivable – ATXI | 75 |
| | 75 |
|
| Accumulated deferred income taxes, net | 49 |
| | 108 |
|
| Other assets | 145 |
| | 126 |
|
| Total assets | $ | 9,559 |
| | $ | 8,991 |
|
| Liabilities and Shareholders’ Equity: | | | |
| Current maturities of long-term debt | $ | 350 |
| | $ | — |
|
| Short-term debt | 153 |
| | 470 |
|
| Borrowings from money pool | 24 |
| | 46 |
|
| Accounts payable – affiliates | 39 |
| | 10 |
|
| Other current liabilities | 23 |
| | 12 |
|
| Total current liabilities | 589 |
| | 538 |
|
| Long-term debt | 794 |
| | 697 |
|
| Pension and other postretirement benefits | 37 |
| | 43 |
|
| Other deferred credits and liabilities | 80 |
| | 82 |
|
| Total liabilities | 1,500 |
| | 1,360 |
|
| Commitments and Contingencies (Note 5) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 246.2 and 244.5, respectively | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,694 |
| | 5,627 |
|
| Retained earnings | 2,380 |
| | 2,024 |
|
| Accumulated other comprehensive loss | (17 | ) | | (22 | ) |
| Total shareholders’ equity | 8,059 |
| | 7,631 |
|
| Total liabilities and shareholders’ equity | $ | 9,559 |
| | $ | 8,991 |
|
|
| | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions) | December 31, 2017 | | December 31, 2016 |
| Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | 1 |
|
| Advances to money pool | 13 |
| | 27 |
|
| Accounts receivable – affiliates | 46 |
| | 31 |
|
| Miscellaneous accounts and notes receivable | — |
| | 26 |
|
| Other current assets | 8 |
| | 8 |
|
| Total current assets | 67 |
| | 93 |
|
| Investments in subsidiaries | 7,944 |
| | 7,498 |
|
| Note receivable – ATXI | 75 |
| | 350 |
|
| Accumulated deferred income taxes, net | 222 |
| | 419 |
|
| Other assets | 140 |
| | 135 |
|
| Total assets | $ | 8,448 |
| | $ | 8,495 |
|
| Liabilities and Shareholders’ Equity: | | | |
| Short-term debt | 383 |
| | 507 |
|
| Borrowings from money pool | 28 |
| | 33 |
|
| Accounts payable – affiliates | 6 |
| | 13 |
|
| Other current liabilities | 27 |
| | 17 |
|
| Total current liabilities | 444 |
| | 570 |
|
| Long-term debt | 696 |
| | 694 |
|
| Pension and other postretirement benefits | 37 |
| | 45 |
|
| Other deferred credits and liabilities | 87 |
| | 83 |
|
| Total liabilities | 1,264 |
| | 1,392 |
|
| Commitments and Contingencies (Note 4) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,540 |
| | 5,556 |
|
| Retained earnings | 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (18 | ) | | (23 | ) |
| Total shareholders’ equity | 7,184 |
| | 7,103 |
|
| Total liabilities and shareholders’ equity | $ | 8,448 |
| | $ | 8,495 |
|
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2019, 2018, and 2017 |
| (In millions) | 2019 | | 2018 | | 2017 |
| Net cash flows provided by operating activities | $ | 491 |
| | $ | 550 |
| | $ | 454 |
|
| Cash flows from investing activities: | | | | | |
| Money pool advances, net | (26 | ) | | (63 | ) | | 14 |
|
| Notes receivable – ATXI, net | — |
| | — |
| | 275 |
|
| Investments in subsidiaries | (142 | ) | | (208 | ) | | (151 | ) |
| Other | 5 |
| | 5 |
| | 6 |
|
| Net cash flows provided by (used in) investing activities | (163 | ) | | (266 | ) | | 144 |
|
| Cash flows from financing activities: | | | | | |
| Dividends on common stock | (472 | ) | | (451 | ) | | (431 | ) |
| Short-term debt, net | (317 | ) | | 87 |
| | (124 | ) |
| Money pool borrowings, net | (22 | ) | | 18 |
| | (5 | ) |
| Issuances of long-term debt | 450 |
| | — |
| | — |
|
| Issuances of common stock | 68 |
| | 74 |
| | — |
|
| Repurchases of common stock for stock-based compensation | — |
| | — |
| | (24 | ) |
| Employee payroll taxes related to stock-based compensation | (29 | ) | | (19 | ) | | (15 | ) |
| Debt issuance costs | (4 | ) | | — |
| | — |
|
| Net cash flows used in financing activities | (326 | ) | | (291 | ) | | (599 | ) |
| Net change in cash, cash equivalents, and restricted cash | $ | 2 |
| | $ | (7 | ) | | $ | (1 | ) |
| Cash, cash equivalents, and restricted cash at beginning of year | 1 |
| | 8 |
| | 9 |
|
| Cash, cash equivalents, and restricted cash at end of year | $ | 3 |
| | $ | 1 |
| | $ | 8 |
|
| | | | | | |
| Cash dividends received from consolidated subsidiaries | $ | 445 |
| | $ | 450 |
| | $ | 362 |
|
| | | | | | |
| Noncash financing activity – Issuance of common stock for stock-based compensation | $ | 54 |
| | $ | 35 |
| | $ | — |
|
|
| | | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015 |
| (In millions) | | 2017 | | 2016 | | 2015 |
| Net cash flows provided by operating activities | | $ | 454 |
| | $ | 483 |
| | $ | 551 |
|
| Cash flows from investing activities: | | | | | | |
| Money pool advances, net | | 14 |
| | (27 | ) | | 55 |
|
| Notes receivable – ATXI, net | | 275 |
| | (60 | ) | | (96 | ) |
| Investments in subsidiaries | | (151 | ) | | (123 | ) | | (509 | ) |
| Other | | 6 |
| | 2 |
| | (12 | ) |
| Net cash flows provided by (used in) investing activities | | 144 |
| | (208 | ) | | (562 | ) |
| Cash flows from financing activities: | | | | | | |
| Dividends on common stock | | (431 | ) | | (416 | ) | | (402 | ) |
| Short-term debt, net | | (124 | ) | | 206 |
| | (284 | ) |
| Money pool borrowings, net | | (5 | ) | | 19 |
| | 14 |
|
| Issuances of long-term debt | | — |
| | — |
| | 700 |
|
| Debt issuance costs | | — |
| | — |
| | (6 | ) |
| Share-based payments | | (39 | ) | | (83 | ) | | (12 | ) |
| Net cash flows provided by (used in) financing activities | | (599 | ) | | (274 | ) | | 10 |
|
| Net change in cash and cash equivalents | | $ | (1 | ) | | $ | 1 |
| | $ | (1 | ) |
| Cash and cash equivalents at beginning of year | | 1 |
| | — |
| | 1 |
|
| Cash and cash equivalents at end of year | | $ | — |
| | $ | 1 |
| | $ | — |
|
| | | | | | | |
| Cash dividends received from consolidated subsidiaries | | $ | 362 |
| | $ | 465 |
| | $ | 575 |
|
| | | | | | | |
| Noncash investing activity – investments in subsidiaries | | — |
| | — |
| | (38 | ) |
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December DECEMBER 31, 20172019
NOTE 1 – BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. Ameren Corporation (parent company only) has accounted for its subsidiaries using the equity method. These financial statements are presented on a condensed basis.
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. See Note 13 – Related-party Transactions under Part II, Item 8, of this report for information on the tax allocation agreement between Ameren Corporation (parent company only) and its subsidiaries.
NOTE 2 – CASH AND CASH EQUIVALENTS
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheet as of December 31, 2019and2018:
|
| | | | | | | |
| | 2019 | | 2018 |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Restricted cash included in “Other current assets” | 3 |
| | 1 |
|
| Total cash, cash equivalents, and restricted cash | $ | 3 |
| | $ | 1 |
|
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
NOTE 23 – SHORT-TERM DEBT AND LIQUIDITY
Ameren, Ameren Services, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the Credit Agreements and the commercial paper programs
through a non-state-regulated subsidiary money pool agreement. All participants may borrow from or lend to the non-state-regulated money pool. The total amount available to pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. Interest revenues and interest charges related to non-state-regulated money pool advances and borrowings were immaterial in 2015, 2016,2017, 2018, and 2017.2019.
Ameren Corporation (parent company only) had a total of $46$10 million in guarantees outstanding, primarily for ATXI, that were not recorded on its December 31, 20172019 balance sheet. The ATXI guarantees were issued to local governments as assurance for potential remediation of damage caused by ATXI construction.
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).
NOTE 3 4 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on Ameren Corporation’s (parent company only) long-term debt, indenture provisions, and restricted cash balance.forward sale agreement related to common stock.
NOTE 4 5 – COMMITMENTS AND CONTINGENCIES
See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies of Ameren Corporation (parent company only).
NOTE 5 – DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for information regarding the divestiture transactions and discontinued operations.
NOTE 6 – OTHER INCOME TAXES(EXPENSE), NET
See Note 12 –The following table presents the components of “Other Income Taxes under Part II, Item 8,(Expense), Net” in the Condensed Statement of this reportIncome and Comprehensive Income for information regarding the impactsyears ended December 31, 2019, 2018, and 2017:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| Other Income (Expense), Net | | | | | |
| Non-service cost components of net periodic benefit income | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| Charitable donations | (3 | ) | | (13 | ) | | — |
|
| Other expense, net | (1 | ) | | (1 | ) | | — |
|
| Total Other Income (Expense), Net | $ | (2 | ) | | $ | (12 | ) | | $ | 2 |
|
NOTE 7 – INCOME TAXES
During the year ended December 31, 2017, Ameren (parent) recorded $110 million in income tax expense and reduction in accumulated deferred income taxes as a result of the TCJATCJA. During the year ended December 31, 2018, Ameren (parent) updated its provisional estimate and recorded $5 million of income tax expense and reduction in accumulated deferred income taxes, primarily due to the application of proposed IRS regulations on Ameren Corporation (parent company only).depreciation transition rules.
| | SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2017, 2016, AND 2015 | |
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017 | | SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, AND 2017 |
| (in millions) | | | | | | | | | | | | | | | | | | | |
| Column A | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| Description | Balance at Beginning of Period | | (1) Charged to Costs and Expenses | | (2) Charged to Other Accounts(a) | | Deductions(b) | | Balance at End of Period | | Balance at Beginning of Period | | (1) Charged to Costs and Expenses | | (2) Charged to Other Accounts(a) | | Deductions(b) | | Balance at End of Period |
| Ameren: | | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | | |
| 2019 | | | $ | 18 |
| | $ | 26 |
| | $ | 4 |
| | $ | 31 |
| | $ | 17 |
|
| 2018 | | | 19 |
| | 27 |
| | 4 |
| | 32 |
| | 18 |
|
| 2017 | $ | 19 |
| | $ | 26 |
| | $ | 7 |
| | $ | 33 |
| | $ | 19 |
| | 19 |
| | 26 |
| | 7 |
| | 33 |
| | 19 |
|
| 2016 | 19 |
| | 32 |
| | 3 |
| | 35 |
| | 19 |
| |
| 2015 | 21 |
| | 33 |
| | 5 |
| | 40 |
| | 19 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | | |
| 2019 | | | $ | 5 |
| | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | 3 |
|
| 2018 | | | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
| 2017 | $ | 11 |
| | $ | (6 | ) | (c) | $ | — |
| | $ | — |
| | $ | 5 |
| | 11 |
| | (6 | ) | (c) | — |
| | — |
| | 5 |
|
| 2016 | 6 |
| | 7 |
| | (2 | ) | | — |
| | 11 |
| |
| 2015 | 10 |
| | 4 |
| | (8 | ) | | — |
| | 6 |
| |
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | | |
| 2019 | | | $ | 7 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 7 |
|
| 2018 | | | 7 |
| | 9 |
| | — |
| | 9 |
| | 7 |
|
| 2017 | $ | 7 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 7 |
| | 7 |
| | 9 |
| | — |
| | 9 |
| | 7 |
|
| 2016 | 7 |
| | 10 |
| | — |
| | 10 |
| | 7 |
| |
| 2015 | 8 |
| | 13 |
| | — |
| | 14 |
| | 7 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | |
| 2017 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| 2016 | — |
| | — |
| | — |
| | — |
| | — |
| |
| 2015 | 1 |
| | — |
| | (1 | ) | | — |
| | — |
| |
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | | |
| 2019 | | | $ | 11 |
| | $ | 17 |
| | $ | 4 |
| | $ | 22 |
| | $ | 10 |
|
| 2018 | | | 12 |
| | 18 |
| | 4 |
| | 23 |
| | 11 |
|
| 2017 | $ | 12 |
| | $ | 17 |
| | $ | 7 |
| | $ | 24 |
| | $ | 12 |
| | 12 |
| | 17 |
| | 7 |
| | 24 |
| | 12 |
|
| 2016 | 12 |
| | 22 |
| | 3 |
| | 25 |
| | 12 |
| |
| 2015 | 13 |
| | 20 |
| | 5 |
| | 26 |
| | 12 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | |
| 2017 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| 2016 | — |
| | — |
| | — |
| | — |
| | — |
| |
| 2015 | 1 |
| | — |
| | (1 | ) | | — |
| | — |
| |
| |
| (a) | Amounts associated with the allowance for doubtful accounts relate to the uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act. The amounts relating to the deferred tax valuation allowance are for items that have expired and were removed from both the underlying accumulated deferred income tax account as well as the offsetting valuation account. |
| |
| (b) | Uncollectible accounts charged off, less recoveries. |
| |
| (c) | Includes an adjustment of $3 million to Ameren (parent)’s valuation allowance for certain deferred tax assets existing at December 31, 2017, for the reduction in the income tax rate. |
| |
| ITEM 16. | FORM 10-K SUMMARY |
The Ameren Companies elected not to provide a summary of the Form 10-K.
EXHIBIT INDEX
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: |
| Articles of Incorporation/ By-Laws |
| 3.1(i) | Ameren | | Annex F to Part I of the Registration Statement on Form S-4, File No. 33-64165 |
| 3.2(i) | Ameren | | 1998 Form 10-K, Exhibit 3(i), File No. 1-14756 |
| 3.3(i) | Ameren | | April 21, 2011 Form 8-K, Exhibit 3(i), File No. 1-14756 |
| 3.4(i) | Ameren | | December 18, 2012 Form 8-K, Exhibit 3.1(i), File No. 1-14756 |
| 3.5(i) | Ameren Missouri | | 1993 Form 10-K, Exhibit 3(i), File No. 1-2967 |
| 3.6(i) | Ameren Illinois | | 2010 Form 10-K, Exhibit 3.4(i), File No. 1-3672 |
| 3.7(ii) | Ameren | | February 14, 2017 Form 8-K, Exhibit 3, File No. 1-14756 |
| 3.8(ii) | Ameren Missouri | | December 18, 2014 Form 8-K, Exhibit 3.1, File No. 1-2967 |
| 3.9(ii) | Ameren Illinois | | December 18, 2014 Form 8-K, Exhibit 3.2, File No. 1-3672 |
| Instruments Defining Rights of Security Holders, Including Indentures |
| 4.1 | Ameren | | Exhibit 4.5, File No. 333-81774 |
| 4.2 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756 |
| 4.3 | Ameren | | November 24, 2015 Form 8-K, Exhibits 4.3, 4.4 and 4.5, File No. 1-14756 |
| 4.4 | Ameren | | September 16, 2019 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 |
| 4.5 | Ameren | | June 26, 2017 Form 8-K, Exhibit 4.1, File No. 1-14756 |
| 4.6 | Ameren Ameren Missouri | Indenture of Mortgage and Deed of Trust, dated June 15, 1937 (Ameren Missouri Mortgage), from Ameren Missouri to The Bank of New York Mellon, as successor trustee, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941 | Exhibit B-1, File No. 2-4940 |
4.54.7 | Ameren Ameren Missouri | | Exhibit 4.22, File No. 333-222108 |
4.64.8 | Ameren Ameren Missouri | | Exhibit 4.23, File No. 333-222108 |
4.74.9 | Ameren Ameren Missouri | | Exhibit 4.24, File No. 333-222108 |
4.84.10 | Ameren Ameren Missouri | | Exhibit 4.25, File No. 333-222108 |
4.94.11 | Ameren Ameren Missouri | | 1993 Form 10-K, Exhibit 4.8, File No. 1-2967
|
4.10 | Ameren
Ameren Missouri
| | 2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
|
4.11 | Ameren
Ameren Missouri
| | August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967 |
| 4.12 | Ameren Ameren Missouri | | March 11, 20032000 Form 8-K,10-K, Exhibit 4.4,4.1,
File No. 1-2967 |
| 4.13 | Ameren Ameren Missouri | | August 4, 200323, 2002 Form 8-K, Exhibit 4.4, File No. 1-2967
|
4.14 | Ameren
Ameren Missouri
| | March 31, 2004 Form 10-Q, Exhibit 4.1,4.3,
File No. 1-2967 |
|
| | | |
| 4.14 | Ameren Ameren Missouri | | March 11, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.15 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967 |
| 4.16 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967 |
4.164.17 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967 |
4.174.18 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967 |
4.184.19 | Ameren Ameren Missouri | | September 23, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967
|
4.19 | Ameren
Ameren Missouri
| | January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967 |
| 4.20 | Ameren Ameren Missouri | | July 21,January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967 |
| 4.21 | Ameren Ameren Missouri | | April 8, 2008July 21, 2005 Form 8-K, Exhibit 4.7,4.4,
File No. 1-2967 |
| 4.22 | Ameren Ameren Missouri | | June 19, 2008 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.23 | Ameren Ameren Missouri | | March 23, 2009 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.24 | Ameren Ameren Missouri | | Exhibit 4.45, File No. 333-182258 |
| 4.25 | Ameren Ameren Missouri | | September 11, 2012 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.26 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.27 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.28 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.29 | Ameren Ameren Missouri | | April 6, 2018 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.30 | Ameren Ameren Missouri | | March 6, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.31 | Ameren Ameren Missouri | | October 1, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.32 | Ameren Ameren Missouri | Loan Agreement, dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri, together with Indenture of Trust dated as of December 1, 1992, between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N.A. | 1992 Form 10-K, Exhibit 4.38, File No. 1-2967 |
4.304.33 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.10, File No. 1-2967 |
4.314.34 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967 |
4.324.35 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.11, File No. 1-2967 |
4.334.36 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967 |
4.34 |
| | | |
| 4.37 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.12, File No. 1-2967 |
4.354.38 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967 |
4.364.39 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.13, File No. 1-2967 |
4.374.40 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967 |
4.384.41 | Ameren Ameren Missouri | | Exhibit 4.48, File No. 333-182258 |
|
| | | |
4.394.42 | Ameren Ameren Missouri | | March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.40 | Ameren
Ameren Missouri
| | August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.41 | Ameren
Ameren Missouri
| | September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.42 | Ameren
Ameren Missouri
| | January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.43 | Ameren Ameren Missouri | | July 21,January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.44 | Ameren Ameren Missouri | | April 8, 2008July 21, 2005 Form 8-K, Exhibits 4.34.2 and 4.5,4.3, File No. 1-2967 |
| 4.45 | Ameren Ameren Missouri | | June 19, 2008March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.46 | Ameren Ameren Missouri | | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.47 | Ameren
Ameren Missouri
| | September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967 |
4.484.47 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.48 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.49 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.50 | Ameren
Ameren Missouri
| | June 23, 2016 Form 8-K, Exhibits 4.3, and 4.4, File No. 1-2967 |
4.514.50 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.524.51 | Ameren Ameren Illinois | | Exhibit 4.4, File No. 333-59438 |
4.534.52 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.544.53 | Ameren Ameren Illinois | | Exhibit 4.17, File No. 333-166095 |
4.554.54 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
4.564.55 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
4.574.56 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
4.58 | Ameren
Ameren Illinois
| Indenture of Mortgage and Deed of Trust between Ameren Illinois (successor in interest to Central Illinois Light Company and Illinois Power Company) and Deutsche Bank Trust Company Americas (formerly Bankers Trust Company), as trustee, dated as of April 1, 1933 (CILCO Mortgage), Supplemental Indenture between the same parties dated as of June 30, 1933, Supplemental Indenture between CILCO (predecessor in interest to Ameren Illinois) and the trustee, dated as of July 1, 1933, Supplemental Indenture between the same parties dated as of January 1, 1935, and Supplemental Indenture between the same parties dated as of April 1, 1940 | Exhibit B-1, Registration No. 2-1937; Exhibit B-1(a), Registration No. 2-2093; and Exhibit A, April 1940 Form 8-K, File No. 1-2732 |
4.594.57 | Ameren Ameren Illinois | | |
4.60 | Ameren
Ameren Illinois
| | |
|
| | | |
4.61 | Ameren
Ameren Illinois
| | |
4.62 | Ameren
Ameren Illinois
| | |
4.63 | Ameren
Ameren Illinois
| | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
4.64 | Ameren
Ameren Illinois
| | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
4.65 | Ameren
Ameren Illinois
| | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732 |
4.664.58 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K,8-K, Exhibit 4.1, File No. 1-3672 |
4.674.59 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
4.68 |
| | | |
| 4.60 | Ameren Ameren Illinois | | September 30, 2019 10-Q, Exhibit 4.2, File No. 1-3672 |
| 4.61 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732 |
4.694.62 | Ameren Ameren Illinois | General Mortgage Indenture and Deed of Trust, dated as of November 1, 1992 between Ameren Illinois (successor in interest to Illinois Power Company) and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Ameren Illinois Mortgage) | 1992 Form 10-K, Exhibit 4(cc), File No. 1-3004 |
4.704.63 | Ameren Ameren Illinois | | June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004 |
4.71 | Ameren
Ameren Illinois
| | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 |
4.724.64 | Ameren Ameren Illinois | | April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004 |
4.73 | Ameren
Ameren Illinois
| | October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.74 | Ameren
Ameren Illinois
| | October 7, 2010 Form 8 K,8-K, Exhibit 4.9, File No. 1-3672 |
4.754.65 | Ameren Ameren Illinois | | Exhibit 4.78, File No. 333-182258 |
4.764.67 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.774.68 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.784.69 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.794.70 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.804.71 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.814.72 | Ameren Ameren Illinois | | September 30, 2017 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
4.824.73 | Ameren Ameren Illinois | | November 28, 2017 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.834.74 | Ameren Ameren Illinois | | May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.75 | Ameren Ameren Illinois | | May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.76 | Ameren Ameren Illinois | | November 15, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.77 | Ameren Ameren Illinois | | November 26, 2019 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.78 | Ameren Ameren Illinois | | September 30, 2019 10-Q, Exhibit 4.3, File No. 1-3672 |
| 4.79 | Ameren Ameren Illinois | | |
| 4.80 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.844.81 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K,8-K, Exhibit 4.5, File No. 1-14756 |
4.854.82 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
4.864.83 | Ameren Ameren Illinois | | Exhibit 4.83, File No. 333-182258 |
|
| | | |
4.874.84 | Ameren Ameren Illinois | | April 8, 2008 Form 8-K,September 30, 2019 10-Q, Exhibit 4.4, File No. 1-30041-3672 |
4.884.85 | Ameren Ameren Illinois | | October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.89 | Ameren
Ameren Illinois
| | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
|
| | | |
| 4.86 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.87 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.88 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.89 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.90 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.91 | Ameren
Ameren Illinois
| | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.92 | Ameren
Ameren Illinois
| | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.93 | Ameren
Ameren Illinois
| | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.94 | Ameren
Ameren Illinois
| | December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.91 | Ameren Ameren Illinois | | September 30, 2019 10-Q, Exhibits 4.5 and 4.6, File No. 1-3672 |
| 4.92 | Ameren | | |
| 4.93 | Ameren Missouri | | |
| 4.94 | Ameren Illinois | | |
| Material Contracts |
| 10.1 | Ameren Companies | | June 30, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
| 10.2 | Ameren Ameren Missouri | | December 8, 201611, 2019 Form 8-K, Exhibit 10.1, File No. 1-2967 |
| 10.3 | Ameren Ameren Illinois | | December 8, 201611, 2019 Form 8-K, Exhibit 10.2, File No. 1-3672 |
| 10.4 | Ameren Illinois | | March 31, 2019 10-Q, Exhibit 10.1, File No. 1-3672 |
| 10.5 | Ameren | | August 7, 2019 Form 8-K, Exhibit 10 File No. 1-14756 |
| 10.6 | Ameren | | |
10.510.7 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
10.610.8 | Ameren | | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.710.9 | Ameren | | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.810.10 | Ameren | | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.910.11 | Ameren | | 2010 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1010.12 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.13, File No. 1-14756 |
10.11 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.13, File No. 1-14756 |
10.12 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.13 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.14 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.15 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.16 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.14, File No. 1-14756 |
| 10.17 | Ameren Companies | | |
| 10.18 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1510.19 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.16 |
| | | |
| 10.20 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1710.21 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.22 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.19, File No. 1-14756 |
| 10.23 | Ameren Companies | | |
10.1810.24 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 |
10.1910.25 | Ameren Companies | | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.2010.26 | Ameren Companies | | |
| September 30, 2019 10-Q, Exhibit 10.2, File No. 1-14756 |
| | | |
10.2110.27 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2210.28 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2310.29 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2410.30 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.24, File No. 1-14756 |
| 10.31 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.27, File No. 1-14756 |
| 10.32 | Ameren Companies | | |
10.2510.33 | Ameren Companies | | Exhibit 99, File No. 333-196515 |
10.2610.34 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.2710.35 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.2810.36 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.2910.37 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.3010.38 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.3110.39 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.34, File No. 1-14756 |
| 10.40 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.35, File No. 1-14756 |
| 10.41 | Ameren Companies | | |
| 10.42 | Ameren Companies | | |
| 10.43 | Ameren Companies | | December 13, 20172018 Form 8-K,10-K, Exhibit 10.3,10.36, File No. 1-14756 |
10.3210.44 | Ameren Companies | | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.3310.45 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 |
Statement re: Computation of Ratios |
12.110.46 | Ameren Companies | | |
12.2 | Ameren Missouri | | |
12.3 | Ameren Illinois | | February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756 |
| Subsidiaries of the Registrant |
| 21.1 | Ameren Companies | | |
Consent of Experts and Counsel |
23.1 | Ameren | | |
23.2 | Ameren Missouri | | |
23.3 | Ameren Illinois | | |
Power of Attorney |
24.1 | Ameren | | |
24.2 | Ameren Missouri | | |
24.3 | Ameren Illinois | | |
Rule 13a-14(a)/15d-14(a) Certifications |
31.1 | Ameren | | |
31.2 | Ameren | | |
31.3 | Ameren Missouri | | |
31.4 | Ameren Missouri | | |
|
| | | |
| Consent of Experts and Counsel |
| 23.1 | Ameren | | |
| 23.2 | Ameren Missouri | | |
| 23.3 | Ameren Illinois | | |
| Power of Attorney |
| 24.1 | Ameren | | |
| 24.2 | Ameren Missouri | | |
| 24.3 | Ameren Illinois | | |
| Rule 13a-14(a)/15d-14(a) Certifications |
| 31.1 | Ameren | | |
| 31.2 | Ameren | | |
| 31.3 | Ameren Missouri | | |
| 31.4 | Ameren Missouri | | |
| 31.5 | Ameren Illinois | | |
| 31.6 | Ameren Illinois | | |
| Section 1350 Certifications |
| 32.1 | Ameren | | |
| 32.2 | Ameren Missouri | | |
| 32.3 | Ameren Illinois | | |
| Additional Exhibits |
| 99.1 | Ameren Companies | | 2013 Form 10-K, Exhibit 99.1, File No. 1-14756 |
Interactive Data FileFiles |
| 101.INS | Ameren Companies | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | |
| 101.SCH | Ameren Companies | XBRL Taxonomy Extension Schema Document | |
| 101.CAL | Ameren Companies | XBRL Taxonomy Extension Calculation Linkbase Document | |
| 101.LAB | Ameren Companies | XBRL Taxonomy Extension Label Linkbase Document | |
| 101.PRE | Ameren Companies | XBRL Taxonomy Extension Presentation Linkbase Document | |
| 101.DEF | Ameren Companies | XBRL Taxonomy Extension Definition Document | |
| 104 | Ameren Companies | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; Ameren Missouri, 1-2967; and Ameren Illinois, 1-3672.
*Compensatory plan or arrangement.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
|
| | | | |
| | | AMEREN CORPORATION (registrant) |
| | | | |
| Date: | February 28, 20182020 | By | | /s/ Warner L. Baxter |
| | | | | Warner L. Baxter Chairman, President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | | | | |
| /s/ Warner L. Baxter | | Chairman, President and Chief Executive Officer, and Director (Principal Executive Officer) | | February 28, 20182020 |
| Warner L. Baxter | | | | |
| | | | |
/s/ Martin J. Lyons, Jr.Michael L. Moehn | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | February 28, 20182020 |
Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | | | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 20182020 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
| Cynthia J. Brinkley | | | | |
| | | | | |
| * | | Director | | February 28, 2020 |
| Catherine S. Brune | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
| J. Edward Coleman | | | | |
| | | | |
| * | | Director | | February 28, 20182020 |
| Ward H. Dickson | | | | |
| | | |
| * | | Director | | February 28, 2020 |
| Noelle K. Eder | | | | |
| | | | | |
| * | | Director | | February 28, 2020 |
| Ellen M. Fitzsimmons | | | | |
| | | | |
| * | | Director | | February 28, 20182020 |
| Rafael Flores | | | | |
| | | |
| * | | Director | | February 28, 2020 |
| Richard J. Harshman | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
Walter J. GalvinCraig S. Ivey | | | | |
| | | | |
| * | | Director | | February 28, 2018 |
Richard J. Harshman | | | | |
| | | |
* | | Director | | February 28, 2018 |
Gayle P. W. Jackson | | | | |
| | | |
* | | Director | | February 28, 20182020 |
| James C. Johnson | | | | |
| | | | |
| * | | Director | | February 28, 20182020 |
| Steven H. Lipstein | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
| Stephen R. Wilson | | | | |
| | | | |
| | | |
| *By | /s/ Martin J. Lyons, Jr.Michael L. Moehn | | | | February 28, 20182020 |
| | Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | Attorney-in-Fact | | | | |
|
| | | | |
| | | UNION ELECTRIC COMPANY (registrant) |
| | | | |
| Date: | February 28, 20182020 | By | | /s/ Michael L. MoehnMartin J. Lyons, Jr. |
| | | | | Michael L. MoehnMartin J. Lyons, Jr.
Chairman and President |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
|
| | | | | |
/s/ Michael L. MoehnMartin J. Lyons, Jr. | | Chairman and President, and Director (Principal (Principal Executive Officer) | | February 28, 2018 |
Michael L. Moehn | | | | |
| | | |
/s/ Martin J. Lyons, Jr.
| | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 20182020 |
| Martin J. Lyons, Jr. | | | | |
| | | | |
/s/ Michael L. Moehn | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 2020 |
| Michael L. Moehn | | | | |
| | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal (Principal Accounting Officer) | | February 28, 20182020 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
| Mark C. Birk | | | | |
| | | | |
| * | | Director | | February 28, 20182020 |
| Fadi M. Diya | | | | |
| | | | |
| * | | Director | | February 28, 20182020 |
Gregory L. Nelson | | | | |
| | | |
* | | Director | | February 28, 2018 |
David N. WakemanChonda J. Nwamu | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr.Michael L. Moehn | | | | February 28, 20182020 |
| | Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | Attorney-in-Fact | | | | |
|
| | | | |
| | | AMEREN ILLINOIS COMPANY (registrant) |
| | | | | |
| Date: | February 28, 20182020 | By | | /s/ Richard J. Mark |
| | | | | Richard J. Mark Chairman and President |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
|
| | | | | |
| /s/ Richard J. Mark | | Chairman and President, and Director (Principal (Principal Executive Officer) | | February 28, 20182020 |
| Richard J. Mark | | | | |
| | | | |
/s/ Martin J. Lyons, Jr.Michael L. Moehn | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 20182020 |
Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal (Principal Accounting Officer) | | February 28, 20182020 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
Craig D. NelsonChonda J. Nwamu | | | | |
| | | | |
| * | | Director | | February 28, 20182020 |
Gregory L. NelsonTheresa A. Shaw | | | | |
| | | | | | |
| * | | Director | | February 28, 20182020 |
| David N. Wakeman | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr.Michael L. Moehn | | | | February 28, 20182020 |
| | Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | Attorney-in-Fact | | | | |
