UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| (X) | | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2016.2017. |
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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, Missouri 63103 | | |
| | | (314) 621-3222 | | |
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| 1-2967 | | Union Electric Company | | 43-0559760 |
| | | (Missouri Corporation) | | |
| | | 1901 Chouteau Avenue | | |
| | | St. Louis, Missouri 63103 | | |
| | | (314) 621-3222 | | |
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| 1-3672 | | Ameren Illinois Company | | 37-0211380 |
| | | (Illinois Corporation) | | |
| | | 6 Executive Drive | | |
| | | Collinsville, Illinois 62234 | | |
| | | (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 |
| Ameren Corporation | Common Stock, $0.01 par value per share |
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 |
| Ameren Illinois Company | Preferred Stock, cumulative, $100 par value per share Depositary Shares, each representing one-fourth of a share of 6.625% Preferred Stock, cumulative, $100 par value per share |
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 | (X)ý
| No | ( )¨
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| Union Electric Company | Yes | ( )¨
| No | (X)ý
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| Ameren Illinois Company | Yes | (X)¨
| No | ( )ý
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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 | (X)ý
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| Union Electric Company | Yes | ( )¨
| No | (X)ý
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| Ameren Illinois Company | Yes | ( )¨
| No | (X)ý
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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 | (X)ý
| No | ( )¨
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| Union Electric Company | Yes | (X)ý
| No | ( )¨
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| Ameren Illinois Company | Yes | (X)ý
| No | ( )¨
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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 | (X)ý
| No | ( )¨
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| Union Electric Company | Yes | (X)ý
| No | ( )¨
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| Ameren Illinois Company | Yes | (X)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 | | (X)ý
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| Union Electric Company | | (X)ý
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| Ameren Illinois Company | | (X)ý
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Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| | | Large Accelerated Filer | | Accelerated Filer | | Non-accelerated Filer | | Smaller Reporting Company | | Emerging Growth Company |
| Ameren Corporation | | (X)ý | | ( )¨ | | ( )¨
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| Union Electric Company | | ( )¨
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| Ameren Illinois Company | | ( )¨
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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 | (X)ý
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| Union Electric Company | Yes | ( )¨
| No | (X)ý
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| Ameren Illinois Company | Yes | ( )¨
| No | (X)ý
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As of June 30, 20162017, Ameren Corporation had 242,634,798 shares of its $0.01 par value common stock outstanding. Thethe aggregate market value of these shares ofAmeren 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, 20162017) held by nonaffiliates was $13,000,372,477. The$13,230,607,078. All of the shares of common stock of the other registrants were held by Ameren Corporation as of June 30, 20162017.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 20172018, were as follows:
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| Ameren Corporation | Common stock, $0.01 par value per share: 242,634,798 |
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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 |
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| Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation (parent company of the registrant): 25,452,373 |
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 20172018 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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| PART I | | |
| Item 1. | | |
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| Item 1A. | | |
| Item 1B. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
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| PART II | | |
| Item 5. | | |
| Item 6. | | |
| Item 7. | | |
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| Item 7A. | | |
| Item 8. | | |
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| Item 9. | | |
| Item 9A. | | |
| Item 9B. | | |
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| PART III | | |
| Item 10. | | |
| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
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| PART IV | | |
| Item 15. | | |
| Item 16. | | |
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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.
2006 Incentive Plan – The 2006 Omnibus Incentive Compensation Plan, which provided for compensatory stock-based awards to eligible employees and directors and was replaced prospectively for new grants by the 2014 Incentive Plan.
2014 Incentive Plan – The 2014 Omnibus Incentive Compensation Plan, which provides for compensatory stock-based awards to eligible employees and directors, effective in April 2014.directors.
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 Genco, AERG,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 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 – Ameren Illinois Company, an Ameren Corporation subsidiary that operates rate-regulated electric and natural gas transmission and distribution businesses in Illinois, doing business as 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 transmission and 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 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 engaged in the construction and operation of electric transmission assets.
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.
CILCO – Central Illinois Light Company, 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, that establisheswhich 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, the EPA announced a proposal to repeal the Clean Power Plan.
CO2 – Carbon dioxide.
COL – Nuclear energy center combined construction and operating license.
Cooling degree-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.
Dekatherm – A standard unit of energy equivalent to one million Btus.
DOE – Department of Energy, a United States government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
DynegyElectric margins – Electric revenues less fuel and purchased power costs.
EMANI – Dynegy Inc.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 taxes – The amount of income taxes previously collected from customers that will be returned to customers over periods of time determined by our regulators.
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 changesthe variance in net energy costs greater or less thanfrom the amount set in base rates without a traditional rate proceeding, 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 2016 Illinois law affecting electric distribution utilities. This law allows Ameren Illinois to earn a return on its electric energy efficiencyenergy-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.
FERC – Federal Energy Regulatory Commission, a United States government agency.
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-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.
IBEW – International Brotherhood of Electrical Workers, a labor union.
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 participate 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.
Illinois Credit Agreement – Ameren'sAmeren’s and Ameren Illinois'Illinois’ $1.1 billion senior unsecured credit agreement. The agreement, was amended and restatedwhich expires in December 2016 and,2021, unless extended, will expire in December 2021.extended.
IP – Illinois Power Company, a former Ameren Corporation subsidiary that was 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.Dynegy Inc.
IRS – Internal Revenue Service, a United States government agency.
ISRS – Infrastructure system replacement surcharge, a cost recovery mechanism that allows Ameren Missouri to recover natural gas infrastructure replacement costs from customers without a traditional rate proceeding.
IUOE – International Union of Operating Engineers, a labor union.
Kilowatthour – A measure of electricity consumption equivalent to the use of 1,000 watts of power over one hour.
LIUNA – Laborers’ International Union of North America, a labor union.
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 Valley – AmerenEnergy Medina Valley Cogen, LLC, an Ameren Corporation subsidiary.
MEEIA – Missouri Energy Efficiency Investment Act, a Missouri law that allows electric utilities to recover costs related to MoPSC-approved customer energy efficiencyenergy-efficiency programs.
MEEIA 2013 – Ameren Missouri'sMissouri’s portfolio of customer energy efficiencyenergy-efficiency programs, net shared benefits, and performance incentive for 2013 through 2015, pursuant to the MEEIA, as approved by the MoPSC in August 2012.
MEEIA 2016 – Ameren Missouri'sMissouri’s portfolio of customer energy efficiencyenergy-efficiency programs, throughput disincentive, and performance incentive for March 2016 through February 2019, pursuant to the MEEIA, as approved by the MoPSC in February 2016.
Megawatthour or MWh – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midcontinent Independent System Operator, Inc., an RTO.
Missouri Credit Agreement – Ameren'sAmeren’s and Ameren Missouri'sMissouri’s $1 billion senior unsecured credit agreement. The agreement, was amended and restatedwhich expires in December 2016 and,2021, unless extended, will expire in December 2021.extended.
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.
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. Since May 30, 2015,Substantially all transmission revenues and substantially all transmission charges are excluded from net energy costs as a result of the April 2015 MoPSC electric rate order.costs.
Net shared benefits – Ameren Missouri'sMissouri’s share of the present value of lifetime energy savings, net of program costs, designed to offset sales volume reductions resulting from MEEIA 2013 customer energy efficiencyenergy-efficiency programs.
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 – AluminumA former aluminum smelter located in southeast Missouri that was owned by Noranda and is now owned by ARG International AG.Missouri.
NOx – Nitrogen oxides.
Noranda – Noranda Aluminum, Inc.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a United States government agency.
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.
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 Adjustment tariffs, which permit prudently incurred natural gas costs to be recovered directly from utility customers without a traditional rate proceeding.
PUHCA 2005 – The Public Utility Holding Company Act of 2005.
QIP – Qualifying infrastructure plant. Costs of qualifying infrastructure natural gas plant are included in an Ameren Illinois recovery mechanism.
Rate base – The basis on which a public utility is permitted to earn an allowed rate of return. 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 levels as compared with the associated amounts included in customer rates. Rate increase requests in traditional regulatory rate case proceedingsreviews 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 levels when based on historical periods.
Revenue requirement – The cost of providing utility service to customers, which is calculated as the sum of a utility'sutility’s recoverable operating and maintenance expenses depreciation and amortization expense, taxes, and an allowed return on rate base.base, including a return on invested capital, both debt and equity, and an amount for income taxes.
RFP – Request for proposal.
Rockland Capital – Rockland Capital, LLC, together with the special-purpose entity affiliated with and formed by Rockland Capital, LLC, that acquired the Elgin, Gibson City, and Grand Tower natural-gas-fired energy centers in January 2014.
RTO – Regional transmission organization.
S&P – Standard & Poor’sS&P Global Ratings, Services, 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.
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; it 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, are 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'sutility’s historical or forecasted operating results are used to determine the appropriate revenue requirement.
Throughput disincentive – Ameren Missouri'sMissouri’s reduced margin caused by the current period'speriod’s lower sales volume resulting from MEEIA 2016 customer energy efficiencyenergy-efficiency programs. Recovery of this disincentive is designed to make Ameren Missouri earnings neutral each period from the lost margins caused by its MEEIA 2016 customer energy efficiencyenergy-efficiency programs.
UAWestinghouse – United Association of Plumbers and Pipefitters, a labor union.Westinghouse Electric Company, LLC.
VBA – A volume balancing adjustment for Ameren Illinois'Illinois’ natural gas operations. As a result of this adjustment, revenues from residential and small nonresidential customers will increase or decrease as billing determinants differ from filed amounts. This adjustment ensures that
changes in sales volumes, including deviations from normal weather conditions, do not result in an over- or under-collection of natural gas revenues for these rate classes.
Zero-emission credit – A credit that represents the environmental attributes of one MWh of energy produced from certain zero-emissions nuclear-powered generation facilities, which 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, including any federal income tax reform and changes in regulatory policies and ratemaking determinations, such as those that may result from the complaint case filed in February 2015 with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff, Ameren Missouri’s proceeding with the unanimous stipulation and agreementMoPSC to pass through to customer rates the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA, Ameren Illinois’ natural gas regulatory rate review filed with the MoPSCICC in February 2017 that settlesJanuary 2018, Ameren Missouri’s July 2016Illinois’ 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 case,enacted under the TCJA, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;
the effect of Ameren Illinois participatingIllinois’ participation in a performance-based formula ratemaking processframeworks under the IEIMA and the FEJA, including the direct relationship between Ameren Illinois'Illinois’ return on common equity and 30-year United States Treasury bond yields, and the related financial commitments required by the IEIMA;
our ability to align overall spending, both operating and capital, with frameworks established by our regulators in our attempt to earn our allowed return on equity;commitments;
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 or rates, including additional regulations, interpretations, amendments, or ratestechnical corrections to the TCJA, and any challenges to the tax positions taken by the Ameren Companies;
the effects on demand for our services resulting from technological advances, including advances in customer energy efficiencyenergy-efficiency and private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;
the effectiveness of Ameren Missouri'sMissouri’s customer energy efficiencyenergy-efficiency programs and the related revenues and performance incentives earned under its MEEIA plans;
the effect of the FEJA on Ameren Illinois, including on the allowed return earned on its customer energy efficiency investments and itsIllinois’ ability to achieve the FEJA electric energy efficiency savingenergy-efficiency goals and the resulting impact on its allowed return on program investments;
our ability to align overall spending, both operating and capital, with frameworks established by the FEJA;
the timing of increasing capital expenditureour regulators and operating
expense requirements and our ability to recover these costs in a timely manner;manner in our attempt to earn our allowed returns on equity;
the cost and availability of fuel, such as ultra-low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, zero-emission credits, renewable energy credits, and natural gas for distribution; and the level and volatility of future market prices for such commodities, including our ability to recover the costs for such commodities and our customers'customers’ tolerance for theany related rateprice 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 ultra-low-sulfur coal used for Ameren Missouri’s compliance with environmental regulations;nuclear fuel assemblies from Westinghouse, Callaway energy center’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;
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 Callaway energy center, or, in the absence of insurance, the ability to recover uninsured losses from our customers;
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 impact of adopting new accounting guidance and the application of appropriate accounting rules and guidance;
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 of natural gas transmission and distribution systems and storage facilities, such as leaks, explosions, and mechanical problems, and compliance with natural gas safety regulations;
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'sMissouri’s Callaway energy center, including planned and unplanned outages, and decommissioning costs;
the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
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| • | the impact of current environmental regulations and new, more stringent, or changing requirements, including those related to CO2, 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 costs or investment requirements, result in an |
impairment of our assets, cause us to sell our assets, reduce our customers' 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 negative opinions of us or our utility services that our customers, 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 protect sensitive customer information, increases in rates, or negative media coverage;
the impact of complying with renewable energy portfolio requirements in Missouri;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;
the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments;
the cost and availability of transmission capacity for the
energy generated by Ameren Missouri'sMissouri’s energy centers or required to satisfy Ameren Missouri'sMissouri’s energy sales;
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, dataemployee, financial, and accountoperating system information; and
acts of sabotage, war, terrorism, or other intentionally disruptive acts.
New factors emerge from time to time. Management cannottime, 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 such 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 under PUHCA 2005. Ameren was formed in 1997. Ameren’swhose primary assets are its equity interests in its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI.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'sAmeren’s principal subsidiaries.subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has various other subsidiaries that conduct other activities, such as the provision of 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 distribution,transmission, electric transmissiondistribution, 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 Spoon River, and Mark Twain projects. ATXI is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.
projects, and placed the Spoon River project in service in February 2018.
The following table presents our total employees at December 31, 2016:2017:
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| Ameren Missouri | 3,7073,639 |
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| Ameren Illinois | 3,4293,423 |
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| Ameren Services | 1,4931,553 |
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| Ameren | 8,6298,615 |
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Labor unions at 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, 2016, the IBEW, the IUOE, the LIUNA, and the UA2017, these labor unions collectively represented about 53%52% of Ameren’s total employees. They represented 63%62% and 58%57% of the employees at Ameren Missouri and Ameren Illinois, respectively. The collective bargaining agreements have terms ranging from two and one half years to six years; they expire between 20172018 and 2020.
For additional information about the development of our businesses, our business operations, and factors affecting our results of operations, and financial position, and liquidity, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
BUSINESS SEGMENTS
In the fourth quarter of 2016, Ameren determined it hadhas 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 composed of the aggregated electric transmission businesses of Ameren Illinois and ATXI.
Ameren Missouri has one segment. Ameren Illinois has
three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.
An illustration of Ameren and Ameren Illinois'Illinois’ reporting structures is provided below. For additional information on
financial reporting segments, see Note 1 – Summary of Significant Accounting Policies and Note 1615 – Segment Information under Part II, Item 8, of this report.
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| (a) | Ameren Transmission segment includes associated Ameren (parent) interest charges, Ameren Transmission Company, LLC, ATX East, LLC, and ATX Southwest, LLC. |
(a) Ameren Transmission segment includes associated Ameren (parent) interest charges. It also includes 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'sAmeren’s electric and natural gas jurisdictions, with the Ameren Transmission and Ameren Illinois Electric Distribution businesses experiencing the least amount of regulatory lag. Depending on the jurisdiction, the effects of regulatory lag are mitigated by various means, including the use of a future test year, the implementation of trackers and riders, the level and timing of expenditures, and regulatory frameworks that include annual revenue requirement reconciliations.reconciliations and decoupling of revenues from sales volumes.
The MoPSC regulates rates and other matters for Ameren Missouri. The ICC regulates rates and other matters for Ameren Illinois, as well asIllinois. 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 doesdo not have authority to regulate ATXI'sATXI’s rates. The FERC regulates Ameren Missouri's,Missouri’s, Ameren Illinois'Illinois’, and ATXI'sATXI’s cost-based rates for the wholesale transmission and distribution of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.
The following table summarizes by rate jurisdiction, the key terms of the rate orders in effect for customer billings for each of Ameren'sAmeren’s rate-regulated utilities as of January 1, 2017:
| | | | Rate Regulator | Allowed
Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren's 2016 Operating Revenues(a) | Rate Regulator | Allowed
Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren’s 2017 Operating Revenues(a) |
| Ameren Missouri | | |
Electric service(c)(b) | MoPSC | 9.53% | 51.8% | $7.0 | 55% | MoPSC | 9.2% - 9.7%(c) | (c) | 54% |
Natural gas delivery service(d) | MoPSC | (d) | 52.9% | $0.2 | 2% | MoPSC | (d) | 2% |
| Ameren Illinois | | |
Electric distribution delivery service(e) | ICC | 8.64% | 50.0% | $2.6 | 26% | ICC | 8.40% | 50.0% | $2.7 | 25% |
Natural gas delivery service(f) | ICC | 9.60% | 50.0% | $1.2 | 12% | ICC | 9.60% | 50.0% | $1.2 | 12% |
Electric transmission service(g) | FERC | 10.82% | 51.6% | $1.4 | 3% | FERC | 10.82% | 51.6% | $1.6 | 4% |
| ATXI | | |
Electric transmission service(g) | FERC | 10.82% | 56.3% | $1.1 | 2% | FERC | 10.82% | 56.2% | $1.3 | 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'sMissouri’s electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate. |
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| (c) | Based on the MoPSC's April 2015MoPSC’s March 2017 rate order. Pending MoPSC approvalThis rate order specified that an implicit return on equity was within a range of a stipulation and agreement filed in February 2017, Ameren Missouri may have new electric service rates effective on or before March 20, 2017.9.2% to 9.7%. The February 2017 stipulation and agreementrate order did not specify thea percent of common equity percentage, theor rate base, or the allowedbase. The return on common equity.equity used for allowance for equity funds used during construction is 9.53%. |
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| (d) | Based on the MoPSC'sMoPSC’s January 2011 rate order. This rate order did not specify the allowed return on equity.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'sICC’s December 20162017 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The December 20162017 rate order was based on 20152016 recoverable costs, expected net plant additions for 2016,2017, and the monthly yields during 20152016 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois' 2017Illinois’ 2018 electric distribution delivery service revenues will be based on its 20172018 actual recoverable costs, rate base, common equity percentage, and return on common equity, as calculated under the IEIMA'sIEIMA’s performance-based formula ratemaking framework. |
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| (f) | Based on the ICC'sICC’s December 2015 rate order. The rate order was based on a 2016 future test year and established the VBA.year. |
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| (g) | Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking rate formula ratemaking based on each year'syear’s forecasted information. The 10.82% return, which includes the 50 basis points incentive adder for participation in an RTO, could be lowered by a FERC complaint proceeding filed in February 2015 that is challengingchallenged the allowed return on common equity for MISO transmission owners and will require customer refunds if the FERC approves the administrative law judge's decision in the February 2015 complaint case.a return on equity lower than that previously collected through rates. |
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'sMissouri’s MEEIA customer energy efficiencyenergy-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 changesthe variance in net energy costs greater than or less thanfrom the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews. Net energy costs, as defined in the FAC, include fuel and purchased power costs, including transportation, net of off-system sales. Under certain conditions, a provision of the FAC allows Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced sales to the New Madrid Smelter.
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 recorddefer the difference between the level ofactual costs incurred costs under GAAP and the level of such costs included in customer rates as a regulatory asset or regulatory liability, whichliability. 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 cases. The return on equity currently used byreviews. Ameren Missouri for purposes ofis not currently recovering any infrastructure replacement costs under the ISRS tariff is 10%.ISRS.
Ameren Illinois
Ameren Illinois Electric Distribution
Ameren Illinois'Illinois’ electric distribution delivery service operating revenues are regulated by the ICC. In 2016,2017, Ameren Illinois'Illinois’ electric distribution delivery service revenues accounted for 89%88% of Ameren Illinois'Illinois’ total electric operating revenues.
Ameren Illinois participates in the performance-based formula ratemaking processframework established pursuant to the IEIMA.
IEIMA and the FEJA. The IEIMA was designed to provideprovides for the recovery of actual costs of electric delivery service that are prudently incurred and to reflect the utility'suse 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, including extending the IEIMA formula ratemaking processframework through 2022, and clarifying that a common equity ratio of up to and including 50% is prudent. Also, beginningBeginning in 2017, the FEJA decouplesallowed Ameren Illinois to recover, within the following two years, its electric distribution revenues established inrevenue requirement for a rate proceeding fromgiven year, independent of actual sales volumesvolumes. Prior to the FEJA, Ameren Illinois’ revenues were affected by providing that any revenue changes driven by actual electric distributionthe timing of sales volumes differingdue to seasonal rates and changes in volumes resulting from, sales volumes reflected in that year's rates will be collected from or refunded to customers within two years.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 createsimplemented a customer surcharge relating to certain nuclear energy centers located in Illinois that,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'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 under the IEIMA.standards. Failure to achieve the standards would result in a reduction in the company'scompany’s allowed return on equity calculated under the formula.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 onfrom inactive meters, and a reduction in uncollectible accountsbad debt expense. The IEIMAregulatory framework applicable to electric
distribution service provides for return on equity penalties totaling up to 34 basis points throughin 2018, and up to 38 basis points in each year from 2019 through 2022, if thethese 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 totalminimum 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 2016,From 2012 through 2017, Ameren Illinois has invested $383$508 million in IEIMA capital projects toward its $625 million requirement.
Ameren Illinois employs cost recovery mechanisms for power procurement, customer energy efficiencyenergy-efficiency program costs incurred before June 2017, and certain environmental costs andas well as bad debt expense and the costs of certain asbestos-related claims not recovered in base rates. Ameren Illinois also has a tariff rider to recover the costs of certain asbestos-related claims.
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'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 efficiencyenergy-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'sstate’s natural gas infrastructure through a QIP rider. Without legislative action, the QIP rider will expire in December 2023. Ameren Illinois'Illinois’ QIP rider allows a surcharge to be added to customers'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'Illinois’ transmission operating revenues are regulated by the FERC. In 2016,2017, Ameren Illinois'Illinois’ transmission service operating revenues accounted for 11%12% of Ameren Illinois'Illinois’ electric operating revenues. See Ameren Transmission below for additional information regarding Ameren Illinois'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;MISO, and their transmission rates are calculated in accordance with the MISO OATT. 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. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity to 10.32%, or a 10.82% total return on common equity with the inclusion of the 50 basis point adder for participation in an RTO. This September 2016 order required the issuance of customer refunds, with interest, for the 15-month period ended February 2015. The refunds are expected to be issued in the first half of 2017. The new allowed return on common equity is reflected in rates prospectively from the September 2016 effective date of the order. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by FERC, would lower the allowed base return on common equity to 9.70%, or a 10.20% total return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. It would also require the issuance of customer refunds, with interest, for the 15-month period ended May 2016.The FERC is
expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. That final order will determine the allowed return on common equity for the 15-month period ended May 2016. That final order will also establish the allowed return on common equity that will apply prospectively from its expected second quarter 2017 effective date, replacing the current 10.82% total return on common equity, which became effective in September 2016.
Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking rate formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated each January with forecasted information. A reconciliation duringat 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.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 atin Ameren TransmissionTransmission’s and Ameren Illinois Transmission.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 rate incentives relatingowners, 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, discussed below, which allow construction work in progress to be included in rate base, thereby improving the timeliness of cash recovery.
The three MISO-approved multi-value projects are primarily being developed by ATXI and are referred to as 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 western Indianaeastern Missouri across Illinois to eastern Missouri.western Indiana. ATXI has obtained a certificate of public convenience and necessity and project approvals from the ICC and the MoPSC for each state'sstate’s portion of the Illinois Rivers project. The last sectionline segment of this project is expected to be completed in 2019.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.Missouri and connects Iowa to the Illinois Rivers project. In 2015, ATXI obtained a certificate of public convenience and necessity and project approval from the ICC for the Spoon River project and construction activities are continuing on schedule. In April 2016,January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. Before starting construction, ATXI must obtain assents for road crossings from the five counties where the line will be constructed. None of the five county commissions have approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in each of the five county circuit courts to obtain the assents. A decision in each of the five lawsuits is expected in 2017. ATXI plans to complete the Spoon River project in 2018 and the Mark Twain project in 2019; however, further delays in obtainingby the consents could delay the completion dateend of the Mark Twain project. ATXI's total investment in2019.
The FERC has approved transmission rate incentives relating to the three MISO-approved multi-value projects, is expectedwhich allow construction work in progress to be more than $1.6 billion.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 electric system. These standards are developed and enforced by the NERC pursuant to authority delegated to it by the FERC. If any of Ameren Missouri, Ameren Illinois or ATXI are determinedis found not to be in compliance with any of these mandatory reliability standards, theyit could incur substantial monetary penalties and other sanctions.
Under PUHCA 2005, the FERC and any state public utility regulatory agency may access books and records of Ameren and its subsidiaries that are determinedfound to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries that may affect jurisdictional rates. PUHCA 2005 also permits the MoPSC and the ICC to request that the FERC review cost allocations by Ameren Services to other Ameren companies.
Operation of Ameren Missouri’s Callaway energy center is subject to regulation by the NRC. The license for the Callaway energy center expires in 2044. Ameren Missouri’s Osage hydroelectric energy center and Taum Sauk pumped-storage hydroelectric energy center, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other aspects, the general operation and maintenance of the projects. The licenselicenses for the Osage hydroelectric energy center expires in 2047. The license forand the Taum Sauk pumped-storage hydroelectric energy center expiresexpire in 2044.2047 and 2044, respectively. Ameren Missouri’s Keokuk energy center and its dam in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.
For additional information on regulatory matters, see Note 2 – Rate and Regulatory Matters, Note 109 – Callaway Energy Center, and Note 1514 – 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 statutes and regulations relating to the protection of the safety and health of our personnel, the public, and the environment. These environmental statutes and regulations 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 and the management of waste and byproduct materials. Failure to comply with these statutes or regulations could have material adverse effects on us. We could be subject to criminal or civil penalties by
regulatory agencies, or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations 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, 2016,2017, Ameren Missouri’s fossil-fueledfossil fuel-fired energy centers represented 18%17% and 34%33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations impactingthat apply to air emissions from the electric utility industry include the regulationNSPS, 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 existing power plants through the Clean Power Plan and from new power plants through the revised NSPS; the CSAPR, which requires further reductions of SO2 emissionsplants. Water intake and NOx emissions from power plants; a regulation governing management and storage of CCR; the MATS, which requires reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; effluent standards applicable to wastewater discharges from power plants; and regulationsplants are regulated under the Clean Water Act thatAct. Such regulation could require significant capital expenditures, such as 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 EPA also periodically reviews and revises national ambient air quality standards, including those standards associated with emissions from power plants, such as particulate matter, ozone, SO2 and NOx. Certain of these regulations are being or are likely to be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. Although many details of future regulations are unknown, the individual or combined effects of recentexisting environmental regulations could result in significant capital expenditures, and increased operating costs, for Ameren and Ameren Missouri.Compliance with these environmental laws and regulations could be prohibitively expensive, result inor the closure or alteration of the operation ofoperations at some of Ameren Missouri’s energy centers, or require further capital investment. centers.Ameren and Ameren Missouri expect that thesesuch compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the nature and timing of costs and their recovery could result inbe 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'sMissouri’s natural gas customers and Ameren Illinois'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, reductions toregulation of CO2 emissions, wastewater discharge standards, remediation efforts, CCR management regulations, and a discussion of the EPA’s allegations of violations of the Clean Air Act and Missouri law in connection with projects at Ameren Missouri'sMissouri’s Rush Island energy center, see Note 1514 – Commitments and Contingencies under Part II, Item 8, of this report.
TRANSMISSION
Ameren owns an integrated transmission system that is composed of the transmission assets of Ameren Missouri, Ameren Illinois, and ATXI. Ameren also operates two balancing authority areas: AMMO and AMIL. During 2016,2017, the peak demand was 7,6817,814 megawatts in AMMO and 8,8688,877 megawatts in AMIL. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
Ameren Missouri, Ameren Illinois, and ATXI are transmission-owning members of MISO. Ameren Missouri is authorized by the MoPSC to participate in MISO through May 2018. In2020. The previously required cost-benefit study related to Ameren Missouri’s continued participation in MISO, as required periodically by the MoPSC and originally expected to be filed in 2017, was deferred upon approval of the MoPSC. Ameren Missouri expects to file athe periodic cost-benefit study requiredin 2020, based on the deferral granted by MoPSC, as it has done periodically since it joined MISO, that evaluates the costs and benefits of Ameren Missouri's continued participation in MISO beyond May 2018.MoPSC.
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. OwnersThe Ameren Companies, like all owners and operators including the Ameren Companies, 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, whichand are all 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 absence of sufficient owned generation.
Ameren Missouri files a nonbinding 20-year integrated resource plan with the MoPSC every three years. The most recent integrated resource plan, filed in September 2017, includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable generation by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, adding 100 megawatts of solar generation over the next 10 years, retiring coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs, and adding cost-effective demand response programs.
Ameren Missouri continues to evaluate its longer-term needs for new generating capacity. The potential need for a new energy center construction is dependent on several key factors, including continuation of and customer participation in energy efficiencyenergy-efficiency programs and distributed generation, load growth, technological advancements, costs of generation alternatives, environmental regulation of coal-fired power plants, and state renewable portfolio standards, which could lead to the retirement of current baseload assets before the end of their useful lives or alterations in the manner in whichway those assets operate. Because of the significant time required to plan, acquire permits for, and build a baseload energy center,
Ameren Missouri continues to study alternatives and to take steps to preserve options to meet future demand. Steps include evaluating the potential for further diversification of Ameren Missouri’s generation portfolio through renewable energy generation, including wind and solar generation, additional customer energy-efficiency and demand response programs, distributed energy efficiency programsresources, and options for renewable energy generation, and maintaining options for natural-gas-fired generation to further diversify Ameren Missouri's generation portfolio.storage.
Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three years and will file its next plan in 2017. Ameren Missouri's integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, was a 20-year plan that supported a more diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, hydro, and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as those energy centers reach the end of their useful lives, expanding customer energy efficiency programs, and adding natural-gas-fired combined cycle generation.
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 109 – Callaway Energy Center, and Note 1514 – Commitments and Contingencies under Part II, Item 8, of this report.
Ameren Illinois
In Illinois, while electric transmission and distribution service rates are regulated, but power supply prices are not regulated.not. Although electric customers are allowed to purchase power from an alternative retail electric supplier, Ameren Illinois is required to serve asbe the provider of last resort for its electric distribution customers. In 2017, 2016, and 2015, Ameren Illinois suppliedprocured power on behalf of its customers for 23%, 23%, and 26%, 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 MISO. The IPA administers an RFP process through which Ameren Illinois procures its expected supply obligation.supply. The power and related procurement costs incurred by Ameren Illinois are passed directly to its electric distribution customers through a cost recovery mechanism andmechanism. The costs are reflected in the Ameren Illinois Electric Distribution'sDistribution’s results of operations, but do not affect Ameren Illinois Electric Distribution'sDistribution’s earnings, as any cost isbecause these costs are offset by a corresponding revenue.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'sDistribution’s earnings.
See Note 1413 – Related PartyRelated-party Transactions and Note 1514 – Commitments and Contingencies under Part II, Item 8, of this report for additional information on power procurement in Illinois.
POWER GENERATION
Ameren Missouri owns energy centers that rely on a diverse fuel portfolio, including coal (Ameren Missouri'sMissouri’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'sMissouri’s coal-fired energy centers were constructed prior to 1978. The Callaway nuclear energy center began operation in 1984.1984 and is licensed to operate until 2044. As of December 31, 2016,2017, Ameren Missouri's fossil-fueledMissouri’s fossil fuel-fired energy centers represented 18%17% and 34%33% of Ameren'sAmeren’s and Ameren Missouri'sMissouri’s rate base, respectively. See Item 2 – Properties under Part I of this report for information regarding Ameren Missouri'sMissouri’s electric generation energy centers.
Coal
Ameren Missouri has an ongoing need for coal as fuel for generation, so itand 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, 2016,2017, Ameren Missouri had price-hedged 88% of its expected coal supply and 99% of its coal transportation requirements for generation in 2017.2018. Ameren Missouri has additional coal supply under contract through 2020.2021. The 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. Ameren Missouri burned 17approximately 18.6 million tons of coal in 2016.2017.
About 98%97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Inventories may be adjusted because of generation levels or uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion and maintenance, derailments, and weather. As of December 31, 2016,2017, 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 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 nuclear energy center.
The Callaway energy center requires refueling at 18-month intervals. The last refueling was completed in May 2016.December 2017. The next refueling will be in fall 2017.is scheduled for the spring of 2019. As of December 31, 2016,2017, Ameren Missouri hashad agreements or inventories to price-hedge 97%all of Callaway's fall 2017Callaway’s spring 2019 refueling requirements. Ameren Missouri has inventories and supply contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at least through the 20202022 refueling. Ameren Missouri has fuel fabrication service contracts through at least 2022.
Natural Gas Supply for Generation
To 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, 2016,2017, Ameren Missouri had price-hedged about 21%73% of its expected natural gas supply requirements for generation in 2017.2018.
Renewable Energy
The states ofMissouri and Illinois and Missouri have enacted laws requiringrequire electric utilities to include renewable energy resources in their portfolios.
Illinois required renewable energy resources to equal or exceed 2% of the total electricity that Ameren Illinois supplied to its eligible retail customers as of June 1, 2008, with that percentage increasing to 13% by June 1, 2017. For the 2016 plan year, Ameren Illinois met its requirement that 11.5% of its total electricity for eligible retail customers be procured from renewable energy resources. Starting June 1, 2017, after a transition period, Ameren Illinois will be required to procure renewable energy resources for all of its electric distribution customers, regardless if Ameren Illinois or an alternative retail electric supplier provides power to customers. This requirement will be satisfied through future IPA procurement events.
The FEJA requires Ameren Illinois to offer distributed generation rebates for all classes of customers, including customers who share common solar facilities through a subscription arrangement. The cost of the rebates will be recorded as a regulatory asset, which will be included in rate base and earn a return based on the utility’s weighted average cost of capital. Customers with distributed generation will also be eligible for net metering provisions, subject to certain customer participation levels. Beginning in 2017, the FEJA decouples electric distribution revenues established in a rate proceeding from actual sales volumes, which ensures that Ameren Illinois’ earnings will not be harmed by a reduction in sales volumes.
In Missouri, utilities are required to purchase or generate electricity equal to at least 2%5% of native load sales from
renewable energy sources beginning in 2011, with that2017. That percentage increasingwill increase to at least 15% by 2021, subject to aan average 1% annual limitincrease on customer rate impacts.rates over any 10-year period. At least 2% of each renewable energy portfolio requirement must be derived from solar energy. In 2016,2017, Ameren Missouri met its requirement to purchase or generate at least 5% of its native load sales from renewable energy resources.requirements. Ameren Missouri expects to satisfy the nonsolar requirement intoin 2018 with its Keokuk energy center and its Maryland Heights energy center, and through a 102-megawatt power purchase agreement with a wind farm operator. The Maryland Heights energy center generates electricity by burning methane gas collected from a landfill. Ameren Missouri is meeting the solar energy requirement by purchasing solar-generated renewable energy credits from customer-installed systems and by generating its own solar energy at the O'FallonO’Fallon energy center and at its headquarters building. See Supply of Electric Power above for renewable energy plans incorporated in Ameren Missouri’s integrated resource plan, filed with the MoPSC in September 2017.
State law required 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 the renewable energy requirement. Starting June 1, 2017, Ameren Illinois is required to procure renewable energy resources for all of its electric distribution customers, even if an alternative retail electric supplier provides power to the customer. The FEJA requires Ameren Illinois to procure zero-emission credits in an amount equal to approximately 16% of the actual amount of electricity delivered by Ameren Illinois to retail 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, the variance in actual zero-emission credit costs incurred 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 Efficiency
Ameren Missouri and Ameren Illinois have implemented energy efficiencyenergy-efficiency programs to educate and to help their customers become more efficient users of energy. In Missouri, the MEEIA established a regulatory framework that, among other things, allows electric utilities to
recover costs relatedwith respect to MoPSC-approved customer energy efficiencyenergy-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 efficiencyenergy-efficiency programs. Missouri does not have a law mandating energy efficiencyenergy-efficiency standards.
From 2013 through 2015, Ameren Missouri invested $134 million in customer energy efficiency programs and realized $174 million of net shared benefits under the MEEIA 2013 performance plan approved in August 2012.
In February 2016, the MoPSC issued an order approving Ameren Missouri'sMissouri’s MEEIA 2016 plan. That plan which included a portfolio of customer energy efficiencyenergy-efficiency programs along with a rider to collect the program costs, the throughput disincentive, and anya performance incentive earned from customers. The throughput disincentive recovery will replacereplaced the net shared benefits that were collected under the MEEIA 2013 plan. The MEEIA rider will allowallows Ameren Missouri to collect the throughput disincentive without a traditional rate proceeding until lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates, based upon both forecasted program costs and throughput disincentive, will beare reconciled annually to actual results. Ameren Missouri intends to invest $158 million in MEEIA 2016 customer energy efficiencyenergy-efficiency programs. In addition, similar to the MEEIA 2013 plan, that ended in December 2015, the MoPSC'sMoPSC’s order approvedincluded a performance incentive that would provide Ameren Missouri an opportunity to earnprovides for additional revenues by achievingif certain MEEIA 2016 customer energy efficiencyenergy-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. Ameren Missouri must achieve at least 25%
of its energy efficiency goals before it earns a MEEIA 2016 performance incentive.
State law requires Ameren Illinois to offer customer energy efficiencyenergy-efficiency programs. TheIn September 2017, the ICC has issued ordersan order approving Ameren Illinois’ electric and natural gas energy efficiencyenergy-efficiency plans, as well as mechanisms by which program costs can be recovered from customers. For the 12-month period ending May 31, 2016, the ICCThe order authorized electric and natural gas energy efficiencyenergy-efficiency program expenditures of $87$394 million and $16$62 million, respectively.respectively, for the period 2018 through 2021. Additionally, as part of its IEIMA capital project investments, Ameren Illinois expects to invest $438$439 million in smart-grid infrastructure from 2012 to 2021, including smart meters that enable customers to improve their energy efficiency.
Historically, Ameren Illinois has recovered the cost of its energy efficiencyenergy-efficiency programs as they were incurred. Beginning as early asSince June 2017, the FEJA will allowhas allowed Ameren Illinois to earn a return on its electric energy efficiencyenergy-efficiency program investments. Ameren IllinoisIllinois’ electric energy efficiencyenergy-efficiency investments will beare deferred as a regulatory asset, and such investments will earn a return at the company’s weighted averageweighted-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 efficiencyenergy-efficiency investments can also be increased or decreased by up to 200 basis points, baseddepending on the achievement of annual energy savings goals. The FEJA also increased the level of electric energy efficiencyenergy-efficiency saving targets through 2030. Based on a formula provided in the act, Ameren Illinois estimates it can annuallyplans to invest up to $100$99 million per year in electric energy-efficiency programs from 2018 through 2021, up2021. Ameren Illinois plans to $107 million annually from 2022 through 2025, and up to $114 million annually from 2026make similar yearly investments in electric energy-efficiency programs through 2030. The ICC has the ability tocan lower the electric energy efficiencyenergy-efficiency saving goals if theresufficient cost-effective measures are insufficient cost effective measuresnot available. The electric energy efficiencyenergy-efficiency program investments and the return on those investments will be recovered through a rider, andrider; they will not be included in the IEIMA formula rate process.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their customers. Ameren Missouri and Ameren Illinois each develop and manage a portfolio of natural gas supply resources. These resources include firm natural gas supply under termthrough agreements with producers, 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 NYMEX futures market and in the OTC financial markets, are
used to hedge the price paid for natural gas. Natural gas purchase 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, 2016,2017, Ameren Missouri and Ameren Illinois had price-hedged 73%66% and 77%75%, respectively, of their expected 20172018 natural gas supply requirements.
For additional information on our fuel and purchased power 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. Also see Note 1 – Summary of Significant Accounting Policies, Note 7 – Derivative Financial Instruments, Note 1413 – Related PartyRelated-party Transactions, and Note 1514 – Commitments and Contingencies under Part II, Item 8 of this report.
INDUSTRY ISSUES
We are facing issues common to the electric and natural gas utility industry. These issues include:
political, regulatory, and customer resistance to higher rates;
the potential for changes in laws, regulations, enforcement efforts, and policies at the state and federal levels;
potential changes to corporate income tax law including anyas a result of the enactment of the TCJA, as well as additional interpretations, regulations, amendments, or technical corrections related to the federal income tax code, and any state income tax reform;
cybersecurity risks, including loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or losstheft or inappropriate release of data, such as utilitycertain types of information, including sensitive customer, dataemployee, financial, and accountoperating system information;
the potential for more intense competition in generation, supply, and distribution, including new technologies and their declining costs;
net metering rules and other changes in existing regulatory frameworks and recovery mechanisms to address the allocation of costs to customers who own generation resources that enable them both to sell power to us and to purchase power from us through the use of our transmission and distribution assets;
legislation or programs to encourage or mandate energy efficiency and renewable sources of power, such as solar, and the lack of consensus as to who should pay for those programs;
pressure on customer growth and usage in light of economic conditions and energy efficiencyenergy-efficiency initiatives;
changes in the structure of the industry as a result of changes in federal and state laws, including the formation and growth of independent transmission entities;
a further expected reduction in the allowed return on common equity on FERC-regulated electric transmission assets;
the availability of fuel and fluctuations in fuel prices;
the availability of a skilled workforce,work force, including retaining the specialized skills of those who are nearing retirement;
regulatory lag;
the influence of macroeconomic factors such ason yields onof United States Treasury securities, and on allowed rates of return
on equity provided by regulators;
higher levels of infrastructure and technology investments and adjustments to customer rates associated with the TCJA that are expected to result in negative or decreased free cash flow, which is defined as cash flows from operating activities less cash flows from investing activities and dividends paid;
public concerns about the siting of new facilities;
| |
| • | complex new and proposed environmental laws, regulations, and requirements, including air and water quality standards, mercury emissions standards, CCR management requirements, and potential CO2 limitations, which may reduce the frequency at which electric generating units are dispatched based upon their CO2 emissions; |
public concerns about the potential environmental impacts from the combustion of fossil fuels and some investors'investors’ concerns about investing in energy companies that have fossil-fueledfossil fuel-fired generation assets;
aging infrastructure and the need to construct new power
generation, transmission, and distribution facilities, which have long time frames for completion, with limited long-term ability to predict power and commodity prices, and regulatory requirements;
public concerns about nuclear generation, decommissioning and the disposal of nuclear waste; and
consolidation of electric and natural gas utility companies.
We are monitoring all these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Note 2 – Rate and Regulatory Matters, Note 109 – Callaway Energy Center, and Note 1514 – 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, | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Electric Sales – kilowatthours (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | 13,245 |
| | 12,903 |
| | 13,649 |
| 12,653 |
| | 13,245 |
| | 12,903 |
|
| Commercial | 14,712 |
| | 14,574 |
| | 14,649 |
| 14,384 |
| | 14,712 |
| | 14,574 |
|
| Industrial | 4,790 |
| | 8,273 |
| | 8,600 |
| 4,469 |
| | 4,790 |
| | 8,273 |
|
| Off-system and other | 7,250 |
| | 7,506 |
| | 6,294 |
| |
| Street lighting and public authority | | 117 |
| | 125 |
| | 126 |
|
| Ameren Missouri retail load subtotal | | 31,623 |
| | 32,872 |
| | 35,876 |
|
| Off-system | | 10,640 |
| | 7,125 |
| | 7,380 |
|
| Ameren Missouri total | 39,997 |
| | 43,256 |
| | 43,192 |
| 42,263 |
| | 39,997 |
| | 43,256 |
|
| Ameren Illinois Electric Distribution: | | | | | | |
Ameren Illinois Electric Distribution(a): | | | | | | |
| Residential | | | | | | 10,985 |
| | 11,512 |
| | 11,554 |
|
| Power supply and delivery service | 4,652 |
| | 4,797 |
| | 4,662 |
| |
| Delivery service only | 6,860 |
| | 6,757 |
| | 7,222 |
| |
| Commercial | | | | | | 12,382 |
| | 12,583 |
| | 12,280 |
|
| Power supply and delivery service | 2,861 |
| | 2,837 |
| | 2,535 |
| |
| Delivery service only | 9,722 |
| | 9,443 |
| | 9,643 |
| |
| Industrial | | | | | | 11,359 |
| | 11,738 |
| | 11,863 |
|
| Power supply and delivery service | 708 |
| | 1,589 |
| | 1,674 |
| |
| Delivery service only | 11,030 |
| | 10,274 |
| | 10,576 |
| |
| Other | 521 |
| | 524 |
| | 518 |
| |
| Street lighting and public authority | | 515 |
| | 521 |
| | 524 |
|
| Ameren Illinois Electric Distribution total | 36,354 |
| | 36,221 |
| | 36,830 |
| 35,241 |
| | 36,354 |
| | 36,221 |
|
| Eliminate affiliate sales | (520 | ) | | (385 | ) | | (67 | ) | (440 | ) | | (520 | ) | | (385 | ) |
| Ameren total | 75,831 |
| | 79,092 |
| | 79,955 |
| 77,064 |
| | 75,831 |
| | 79,092 |
|
| Electric Operating Revenues (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | $ | 1,421 |
| | $ | 1,464 |
| | $ | 1,417 |
| $ | 1,416 |
| | $ | 1,421 |
| | $ | 1,464 |
|
| Commercial | 1,223 |
| | 1,258 |
| | 1,203 |
| 1,207 |
| | 1,223 |
| | 1,258 |
|
| Industrial | 315 |
| | 469 |
| | 475 |
| 305 |
| | 315 |
| | 469 |
|
| Off-system and other | 435 |
| | 279 |
| | 293 |
| |
| Other, including street lighting and public authority | | 115 |
| | 102 |
| | 84 |
|
| Ameren Missouri retail load subtotal | | $ | 3,043 |
| | $ | 3,061 |
| | $ | 3,275 |
|
| Off-system | | 370 |
| | 333 |
| | 195 |
|
| Ameren Missouri total | $ | 3,394 |
| | $ | 3,470 |
| | $ | 3,388 |
| $ | 3,413 |
| | $ | 3,394 |
| | $ | 3,470 |
|
| Ameren Illinois Electric Distribution: | | | | | | | | | | |
| Residential | | | | | | $ | 870 |
| | $ | 894 |
| | $ | 858 |
|
| Power supply and delivery service | $ | 484 |
| | $ | 495 |
| | $ | 468 |
| |
| Delivery service only | 410 |
| | 363 |
| | 308 |
| |
| Commercial | | | | | | 527 |
| | 518 |
| | 474 |
|
| Power supply and delivery service | 251 |
| | 247 |
| | 233 |
| |
| Delivery service only | 267 |
| | 227 |
| | 185 |
| |
| Industrial | | | | | | 113 |
| | 96 |
| | 124 |
|
| Power supply and delivery service | 34 |
| | 71 |
| | 87 |
| |
| Delivery service only | 62 |
| | 53 |
| | 42 |
| |
| Other | 41 |
| | 76 |
| | 80 |
| |
| Other, including street lighting and public authority | | 58 |
| | 41 |
| | 76 |
|
| Ameren Illinois Electric Distribution total | $ | 1,549 |
| | $ | 1,532 |
| | $ | 1,403 |
| $ | 1,568 |
| | $ | 1,549 |
| | $ | 1,532 |
|
| Ameren Transmission: | | | | | | | | | | |
Ameren Illinois Transmission(a) | $ | 232 |
| | $ | 189 |
| | $ | 154 |
| |
Ameren Illinois Transmission(b) | | $ | 258 |
| | $ | 232 |
| | $ | 189 |
|
| ATXI | 123 |
| | 70 |
| | 33 |
| 168 |
| | 123 |
| | 70 |
|
| Ameren Transmission total | 355 |
| | $ | 259 |
| | $ | 187 |
| $ | 426 |
| | $ | 355 |
| | $ | 259 |
|
| Other and intersegment eliminations | (102 | ) | | (81 | ) | | (65 | ) | (97 | ) | | (102 | ) | | (81 | ) |
| Ameren total | $ | 5,196 |
| | $ | 5,180 |
| | $ | 4,913 |
| $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
|
| |
| (a) | Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2017, 2016, and 2015, Ameren Illinois procured power on behalf of its customers for 23%, 23%, and 26%, respectively, of its total kilowatthour sales. |
| |
| (b) | Includes $42 million, $45 million, and $38 million in 2017, 2016, and $35 million in 2016, 2015, and 2014, 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 | % |
|
| | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2016 | | 2015 | | 2014 |
| Source of Ameren Missouri energy supply: | | | | | |
| Coal | 66.2 | % | | 67.1 | % | | 73.5 | % |
| Nuclear | 22.8 |
| | 23.3 |
| | 20.6 |
|
| Hydroelectric | 3.3 |
| | 3.6 |
| | 2.2 |
|
| Natural gas | 0.7 |
| | 0.3 |
| | 0.2 |
|
| Methane gas and solar | 0.1 |
| | 0.2 |
| | 0.1 |
|
| Purchased – Wind | 0.8 |
| | 0.7 |
| | 0.8 |
|
| Purchased – Other | 6.1 |
| | 4.8 |
| | 2.6 |
|
| Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % |
| | Natural Gas Operating Statistics – Year Ended December 31, | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Natural Gas Sales – dekatherms (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | 6 |
| | 7 |
| | 8 |
| 6 |
| | 6 |
| | 7 |
|
| Commercial | 3 |
| | 3 |
| | 4 |
| 3 |
| | 3 |
| | 3 |
|
| Industrial | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
| Transport | 8 |
| | 7 |
| | 7 |
| 8 |
| | 8 |
| | 7 |
|
| Ameren Missouri total | 18 |
| | 18 |
| | 20 |
| 18 |
| | 18 |
| | 18 |
|
| Ameren Illinois Natural Gas: | | | | | | | | | | |
| Residential | 52 |
| | 55 |
| | 66 |
| 50 |
| | 52 |
| | 55 |
|
| Commercial | 17 |
| | 18 |
| | 23 |
| 15 |
| | 17 |
| | 18 |
|
| Industrial | 3 |
| | 3 |
| | 3 |
| 3 |
| | 3 |
| | 3 |
|
| Transport | 94 |
| | 89 |
| | 91 |
| 98 |
| | 94 |
| | 89 |
|
| Ameren Illinois Natural Gas total | 166 |
| | 165 |
| | 183 |
| 166 |
| | 166 |
| | 165 |
|
| Ameren total | 184 |
| | 183 |
| | 203 |
| 184 |
| | 184 |
| | 183 |
|
| Natural Gas Operating Revenues (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | $ | 77 |
| | $ | 84 |
| | $ | 102 |
| $ | 77 |
| | $ | 77 |
| | $ | 84 |
|
| Commercial | 30 |
| | 34 |
| | 40 |
| 31 |
| | 30 |
| | 34 |
|
| Industrial | 4 |
| | 5 |
| | 7 |
| 4 |
| | 4 |
| | 5 |
|
| Transport and other | 17 |
| | 14 |
| | 15 |
| 14 |
| | 17 |
| | 14 |
|
| Ameren Missouri total | $ | 128 |
| | $ | 137 |
| | $ | 164 |
| $ | 126 |
| | $ | 128 |
| | $ | 137 |
|
| Ameren Illinois Natural Gas: | | | | | | | | | | |
| Residential | $ | 531 |
| | $ | 550 |
| | $ | 675 |
| $ | 532 |
| | $ | 531 |
| | $ | 550 |
|
| Commercial | 153 |
| | 163 |
| | 208 |
| 146 |
| | 153 |
| | 163 |
|
| Industrial | 12 |
| | 13 |
| | 23 |
| 14 |
| | 12 |
| | 13 |
|
| Transport and other | 58 |
| | 57 |
| | 70 |
| 51 |
| | 58 |
| | 57 |
|
| Ameren Illinois Natural Gas total | $ | 754 |
| | $ | 783 |
| | $ | 976 |
| $ | 743 |
| | $ | 754 |
| | $ | 783 |
|
| Other and intercompany eliminations | (2 | ) | | (2 | ) | | — |
| (2 | ) | | (2 | ) | | (2 | ) |
| Ameren total | $ | 880 |
| | $ | 918 |
| | $ | 1,140 |
| $ | 867 |
| | $ | 880 |
| | $ | 918 |
|
| | | | | | | | | | | |
Rate Base Operating Statistics – At December 31, | 2016 | | 2015 | | 2014 | |
Rate Base Statistics – At December 31, | | 2017 | | 2016 | | 2015 |
| Rate Base (in billions): | | | | | | | | | | |
| Coal Generation | $ | 2.0 |
| | $ | 2.0 |
| | $ | 2.2 |
| |
| Natural Gas Generation | 0.4 |
| | 0.5 |
| | 0.5 |
| |
| Nuclear and Renewables Generation | 1.8 |
| | 1.7 |
| | 1.8 |
| |
| Electric and Natural Gas Transmission and Distribution | 9.4 |
| | 8.2 |
| | 7.4 |
| |
| Ameren total | $ | 13.6 |
| | $ | 12.4 |
| | $ | 11.9 |
| |
| 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 |
|
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 an Interneta website maintained by the SEC (www.sec.gov). Ameren also uses itsAmeren’s own website as ais our channel of distribution for material information about the Ameren Companies. Financial and other material information regarding the Ameren Companies 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.
We are subject to federal, state, and local regulation. This extensive regulatory framework, some of which is more specifically identified in the following risk factors, regulates, among other matters, the electric and natural gas utility industries; the rate and cost structure of utilities; the operation of nuclear energy centers;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 the regulatory framework,
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, andappeal. Rates are also subject to legislative actions, which are largely outside of our control. Any events that 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.
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 mechanisms that allow electric or natural gas rates to be adjusted without a traditional rate proceeding. These mechanisms are not permanent and could be changed or terminated.
Ameren Missouri'sMissouri’s electric and natural gas utility rates and Ameren Illinois'Illinois’ natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Ameren Missouri'sMissouri’s rates established in those proceedings are primarily based on
historical costs and revenues. Ameren Illinois'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.regulator, including a return on invested capital, both debt and equity, and an amount for income taxes. Although rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, 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.
InWith respect to Ameren Missouri’s electric and natural gas utility rates, in years when capital investments and operations costs rise or customer usage declines below those levels reflected in rates, we may not be able to earn the allowed return established by the regulator. This could result in the deferral or cancellation of planned capital investments, which could reduce the rate base investments on which we earnAmeren Missouri earns a rate of return. 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.
As a result of its participation in the performance-based formula ratemaking processframework established pursuant to the IEIMA and the FEJA, Ameren Illinois’ return on equity for its electric distribution businessservice 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'sAmeren’s and Ameren Illinois'Illinois’ results of operations, financial position, and liquidity.
Ameren Illinois is participatingparticipates in thea performance-based formula ratemaking processframework established pursuant to the IEIMA for its electric distribution business.service. Beginning in 2017, the FEJA allowed Ameren Illinois to recover its electric distribution revenue requirement for a given year, independent of actual sales volumes. Since June 2017, the FEJA has also allowed Ameren Illinois to earn a return on its electric energy-efficiency program investments, which is subject to performance-based formula ratemaking. The ICC annually reviews Ameren Illinois’ rate filings under the IEIMA 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 return on equity component ofunder the formula rateIEIMA 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 processframeworks for both its electric distribution businessservice and its electric energy-efficiency investments is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. AWith respect to electric distribution service, a 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7$8 million change in Ameren'sAmeren’s and Ameren Illinois'Illinois’ net income, based on its 20172018 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 equity calculated under the formula.ratemaking formulas. The IEIMAperformance 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 totalingup to 34 basis points in each of 2017 through 2018, and up to 38 basis points in each year from 2019 through 2022, if thethese 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.
Between 2012 and 2021, Ameren Illinois is required to invest a totalminimum 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.
WhenWithout the extension of formula ratemaking, the IEIMA performance-based formula ratemaking processframework expires at the end of 20222022. Ameren Illinois willwould 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 $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.
We are subject to various environmental laws and regulations. Significant capital expenditures are required to achieve and to maintain compliance with these laws and regulations. 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, or exposure to fines and liabilities, all of which could adversely affect our results of operations, financial position, and liquidity.
We are subject to various environmental laws 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 diverserespect to environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage, 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.
We are also subject to liability under environmental laws that address the remediation of environmental contamination ofon 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, 2016,2017, Ameren Missouri’s fossil-fueledfossil fuel-fired energy centers represented 18%17% and 34%33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations impactingthat apply to air emissions from the electric utility industry include the regulationNSPS, 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 existing power plants through the Clean Power Plan and from new power plants through the revised NSPS; the CSAPR, which requires further reductions of SO2 emissionsplants. Water intake and NOx emissions from power plants; a regulation governing management and storage of CCR; the MATS, which requires reduction of emissions of
mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; effluent standards applicable to wastewater discharges from power plants; and regulationsplants are regulated under the Clean Water Act thatAct. Such regulation could require significant capital expenditures, such as 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 EPA also periodically reviews and revises national ambient air quality standards, including those standards associated with emissions from power plants, such as particulate matter, ozone, SO2 and NOx. Certain of these regulations are being or are likely to be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. Although many details of future regulations are unknown, the individual or combined effects of recentexisting environmental regulations could result in significant capital expenditures, and increased operating costs, foror the closure or alteration of operations at some of Ameren and Ameren Missouri.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, alleged that in performing projects at its Rush Island coal-fired energy 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 that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceedthen proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase of the litigation.phase. The EPA previously withdrew all claims for penalties and fines.
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 pollution control equipment, as well as increased operations and maintenance expenses.
TheIn 2015, the EPA issued the Clean Power Plan, sets forthwhich would have established CO2emissions standards applicable to existing power plants. The rule was stayed by the United States Supreme Court stayed the rule in February 2016, pending the outcome of various legal challenges. If upheld and implemented,In October 2017, the EPA announced a proposal to repeal the Clean Power Plan would require Missouri and IllinoisPlan. In December 2017, the EPA issued an advanced notice of proposed rulemaking to reducesolicit input from stakeholders as to how the EPA should regulate CO2 emissions from existing power plants within their states significantly below 2005 levels by 2030. The rule contains interim compliance periods commencing in 2022under the Clean Air Act. Accordingly, we no longer expect the Clean Power Plan to take effect. However, the EPA may issue new requirements that would require each state to demonstrate progress in achieving itsregulate CO2 emissions reduction target. Ameren continues to evaluate the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and to its level of investment in customer energy efficiency programs, renewable energy, and
other forms of generation. Significant uncertainty exists regarding the impact of the Clean Power Plan as its implementation will depend upon plans to be developed by the states. Numerous legal challenges are pending, which could result in the rule being declared invalid or the nature and timing of CO2 emissions reductions being revised. All implementation requirements are deferred until such time as these legal challenges are concluded. Appeals are not expected to conclude prior to 2018.from existing power plants. We cannot predict the outcome of suchthe EPA’s future rulemaking or the outcome of any legal challenges or their impactrelating to such future rulemakings, any of which could have an adverse effect on our results of operations, financial position, orand liquidity. If the rule is ultimately upheld and not rescinded or altered significantly by the new federal administration, compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could in turn result in increased operating costs and require Ameren Missouri to make unplanned or accelerated capital expenditures.
Ameren and Ameren Missouri have incurred and expect to incur significant costs relatedwith 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'sMissouri’s coal-fired energy centers, which, in turn, could lead to increased liquidity needs and higher financing costs. Actions required to ensure that ourAmeren 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 that are not recoverable through rates might result in Ameren Missouri closing coal-fired energy centers earlier than planned, which wouldplanned. If these costs are not recoverable through rates, it could lead to an impairment of assets and reduced revenues. We are unable to predictAny of the ultimate impact of these mattersforegoing could have an adverse effect on our results of operations, financial positions, and liquidity.
Following recent changes inThe TCJA is complex and significantly affects the leadershipAmeren Companies. As a result of the federal government, there have been various legislative options proposedTCJA, the Ameren Companies expect lower operating cash flows, driven by lower customer rates, which may need to reform the federal income tax code. Whetherbe funded through debt and/or equity issuances. Further, additional interpretations, regulations, amendments, and technical corrections to the federal income tax code, will be reformed is currently unknown, but any such changesas well as the associated treatment by our regulators, may adversely affect our results of operations, financial position, and liquidity.
Since the 2016 presidential and congressional elections, there have been various legislative options proposed to reformThe TCJA, among other things, reduced the federal income tax code, including reducing the statutory federal corporate income tax rate; allowingrate from 35% to 21%, 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 current tax deduction for all new capital investments; and eliminating the interest deduction as well as other modifications that would change the amount of income subject to income tax. Any federal
income tax reform would ultimately affect the rates we charge our customers. A reduction in the statutory federal income tax rate would result in a reduction of deferred tax assets and liabilities currently recorded. A lower federal statutory income tax rate may result in a significant one-timenoncash charge to our resultsearnings of operations$154 million as a result of the revaluation of our deferred tax assets nottaxes, largely attributable to our rate-regulated businesses. Additionally, a lowerAmeren (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 federalcorporate income tax rate, may resultwhich 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 significanttiming 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 revenuesthe 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 liquiditytax 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 both the requiredTCJA 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 to customers of excess deferred tax liabilities previously funded by customerstaxes 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 somethe same time period yet(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 reduced collectionTCJA could be subject to potential amendments and technical corrections, any of taxes in customer rates, each without an immediate reduction in our cash tax obligations. Also, changes that would ultimately result in lower taxable income in the futurewhich could prevent us from using all of our tax carryforward benefits before they expire. A current tax deduction for all new capital investments could reduce the level of our rate base growth from current expectations. Although the specific changes and the ultimate timing of federal income tax reform, if implemented at all, are currently unknown, federal income tax reform may 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’, legislators’, and regulators’ opinions of us are affected by many factors, including system reliability, implementation of our investment plans, protection of customer information, rates, and media coverage. To the extent that customers, legislators, or regulators have or develop a negative opinion of us, our results of operations, financial position, and liquidity could be adversely affected.
Service interruptions can occur due to failures of equipment as a result of severe or destructive weather or other causes, and thecauses. 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. Customers'Customers’, legislators'legislators’, and regulators'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, 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 equity we are allowed to earn. 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 to the potential for
regulatory penalties and other sanctions.
The FERC can impose civil penalties of $1approximately $1.2 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards. As owners and operators of bulk power transmission systems and electric energy centers, we are subject to mandatory NERC reliability standards, including cybersecurity standards. Compliance with these mandatory reliability standards may subject us to higher operating costs and may result in increased capital expenditures. If we were found not to be in compliance with these mandatory reliability standards, 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 also conducts audits and reviews of Ameren Missouri's,Missouri’s, Ameren Illinois'Illinois’, and ATXI'sATXI’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 of, and capital improvements to, our electric and natural gas utility infrastructure involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as scheduled, cost disallowances by regulators, and the inability to earn an adequate return on invested capital, any of which could result in higher costs and facility closures.
We expect to incur 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 $11.2$11.4 billion (Ameren Missouri – up to $4.2$4.5 billion; Ameren Illinois – up to $6.4$6.6 billion; ATXI – up to $0.6$0.3 billion) of capital expenditures from 20172018 through 2021.2022. 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. These estimates include allowance for equity funds used during construction. Investments in Ameren’s rate-regulated operations are expected to be recoverable from ratepayers,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 is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, and escalating costs for materials and labor.labor, the ability to obtain required project approvals, and the ability to obtain necessary rights-of-way and easements. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors who do not perform as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on reasonable terms, or other events beyond our control could affect the schedule, cost, and performance of these projects. There is a risk that a power plant mayan 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'sFERC’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 was filed with the FERC in February 2015 that 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'sAmeren’s and Ameren Illinois'Illinois’ earnings by an estimated $7$8 million and $4 million, respectively, based on each company's 2017company’s 2018 projected rate base.
A significant portion of Ameren'sAmeren’s electric transmission investments consists of three separate ATXI projects, to be constructed by ATXI, which have been approved by MISO as multi-value projects. ATXI'sAs of December 31, 2017, ATXI’s expected remaining investment in all three projects was approximately $300 million, with the total investment in the three projects is expected to be more than $1.6 billion.billion The last of these projects is expected to be completed in 2019; however, further delays in obtaining the assents for road crossings could delay the completion date of the Mark Twain project.2019. A failure by ATXI to complete these three projects on time and within projected cost estimates could adversely affect Ameren'sAmeren’s results of operations, financial position, and liquidity.
The FERC has issued orders, which are subject to ongoing litigation, eliminating the right of first refusal for an electric utility to construct within its service territoryWithin MISO, certain new transmission projects for which there will beare eligible for regional cost sharing. If these orders are upheld by the courts,sharing may be subject to competition. Therefore, Ameren wouldmay need to compete to build certain future electric transmission projects in its subsidiaries'subsidiaries’ service territories. Such competition could limit Ameren'sAmeren’s future transmission investment. Conversely, if such FERC orders are not upheld by the courts, the right of first refusal would be expected to be reinstated. In such event, Ameren may lose opportunities to construct electric transmission assets outside of its subsidiaries' service territories and outside of MISO.
Our electric generation, transmission, and distribution facilities are subject to operational risks that could adversely affect our results of operations, financial position, and liquidity.
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;
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 forby Ameren Missouri’s complianceMissouri to comply with environmental regulations;
lack of adequate water required for cooling plant operations;
labor disputes;
suppliers and contractors who do not perform as required under their contracts;
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, solar flares, and electromagnetic pulses;
accidents that might result in injury or loss of life, extensive property damage, or environmental damage;
cybersecurity risks, including loss of operational control of Ameren Missouri'sMissouri’s energy centers and our transmission and distribution systems and loss of data, such asincluding sensitive customer, dataemployee, financial and accountoperating system information, through insider or outsider actions;
failure of other operators'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 occurrences;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 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 ownership and operation of a nuclear energy center creates business, financial, and waste disposal risks.
Ameren Missouri’s ownership of the Callaway energy center subjects it to the 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'sgovernment’s plan to permanently store spent nuclear fuel and, as a result, the risk of being requiredneed 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 center or other United States nuclear facilities;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;
uncertainties with respect toabout contingencies and retrospective premium assessments relating to claims at the Callaway
energy center or any other United States nuclear facilities;
public and governmental concerns about the safety and adequacy of security at nuclear facilities;
uncertainties with respect toabout 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 a single supplier;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 cyber attack, or any accident leading to release of nuclear contamination.
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 nuclear facilities such as the Callaway energy center. In addition, if a serious nuclear incident were to occur, it could adversely affect Ameren'sAmeren’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 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 otherincreased operating risks and costs that could adversely affect our results of operations, financial position, and liquidity.
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. 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 systems could lead to additional capital expenditures, and increased regulation, ofand fines and penalties on 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 expenditures or may require replacement whichthat could adversely affect our results of operations, financial position, and liquidity.
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 nuclear energy 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'scenter’s cost has not been fully recovered, Ameren Missouri may be adversely affected if the MoPSC does not allow such cost isto be recovered in rates. Ameren Missouri may also be adversely affected if the MoPSC does not allowed in rates byallow full or timely recovery of decommissioning costs associated with the MoPSC.retirement of an energy center. 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 additional oversight by our regulators.increased costs associated with regulatory oversight. The frequency and duration of customer outages are among the IEIMA performance standards. Therefore,Any failure to achieve these standards will result in a reduction in Ameren Illinois'Illinois’ allowed return on equity 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, and other factors that reduce energy demand could adversely affect ourAmeren and Ameren Missouri’s results of operations, financial position, and liquidity.
Requirements and incentives to reduce energy consumption have been proposed by regulatory agencies and introduced by legislatures. Conservation and energy efficiency programs are designed to reduce energy demand. Without a regulatory mechanism to ensure recovery, a declinedeclines in energy usage will result in an under-recovery of ourAmeren Missouri’s revenue requirement. 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 losses from energy efficiencyenergy-efficiency efforts not related to its MEEIAenergy-efficiency programs, as well as from distributed generation sources, such as solar panels. In Illinois, the FEJA includes a provision, beginning in 2018, that will reduce Ameren Illinois' allowed return only on electric energy efficiency investments if certain energy savings targets are not achieved. Additionally, macroeconomic factors resulting in low economic growth or contraction within our service territories could reduce energy demand.
Technological advances could reduce or change customer electricity consumption.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'sMissouri’s energy centers. Additionally, technological advances related toin 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. 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. We are also party to collective bargaining agreements that collectively represent about 53%52% of Ameren’s total employees. 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, there 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 impact economic activity in our service territory which, in turn, could adversely affect our results of operations, financial position, and liquidity.
Our industryThere has seenbeen an increase in the number and sophistication of cyber attacks.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 associated withresulting from theft or the inappropriate release of certain types of information, including sensitive customer, employee, financial, and employee data.operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to our 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.
We rely on short-term and long-term debt as significant sources of liquidity and funding for capital requirements not satisfied by our operating cash flow, as well as to refinance long-term debt. By the end of 2018, $8032019, $951 million and $707$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 outstanding short-term debt with long-term debt in 2017.2018 and 2019. The inability to raise debt or equity capital onat reasonable terms, or at all, could negatively affect our ability to maintain and to expand our businesses. Events beyond our control, such as a recession 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. Certain Ameren subsidiaries, such as ATXI, rely on Ameren for access to capital. Circumstances that limit Ameren’s access to capital could impair its ability to provide those subsidiaries with needed capital.
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 intercompanyaffiliate indebtedness. The payment of dividends to Ameren by its
subsidiaries in turn depends on their results of operations, and available cash and other items affecting retained earnings.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 intercompanyaffiliate 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 associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits could adversely affect our financial position and liquidity.
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'customers’ rates and our plan funding requirements. Ameren'sAmeren’s total unfunded obligation under its pension and postretirement benefit plans was $774$551 million as of December 31, 2016.2017. Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. ConsideringBased on Ameren’s assumptions at December 31, 2016,2017, its investment performance in 2016,2017, and its pension funding policy, Ameren expects to make annual contributions of $50less than $1 million to $70$60 million in each of the next five years, with aggregate estimated contributions of $290 million.$120 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 35% and 55%, respectively. These amounts are estimates. They 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 retirement 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.
| |
| 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 1514 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows the anticipated capability of Ameren Missouri'sMissouri’s energy centers at the time of Ameren Missouri'sMissouri’s expected 20172018 peak summer electrical demand:
|
| | | | |
| Primary Fuel Source | Energy Center | Location | Net Kilowatt Capability(a) |
| Coal | Labadie | Franklin County, Missouri | 2,372,000 |
|
| | Rush Island | Jefferson County, Missouri | 1,178,000 |
|
| | Sioux | St. Charles County, Missouri | 968,000972,000 |
|
| | Meramec(b) | St. Louis County, Missouri | 591,000 |
|
| Total coal | | | 5,109,0005,113,000 |
|
| Nuclear | Callaway | Callaway County, Missouri | 1,193,0001,194,000 |
|
| Hydroelectric | Osage | Lakeside, Missouri | 240,000 |
|
| | Keokuk | Keokuk, Iowa | 144,000 |
|
| Total hydroelectric | | | 384,000 |
|
| Pumped-storage | Taum Sauk | Reynolds County, Missouri | 440,000 |
|
| Oil (CTs) | Fairgrounds | Jefferson City, Missouri | 55,000 |
|
| Meramec | St. Louis County, Missouri | 54,000 |
|
| Fairgrounds | Jefferson City, Missouri | 54,00055,000 |
|
| | Mexico | Mexico, Missouri | 54,000 |
|
| | Moberly | Moberly, Missouri | 54,000 |
|
| | Moreau | Jefferson City, Missouri | 54,000 |
|
| Total oil | | | 270,000272,000 |
|
| Natural gas (CTs) | Audrain(c) | Audrain County, Missouri | 600,000608,000 |
|
| | Venice(d) | Venice, Illinois | 488,000491,000 |
|
| | Goose Creek | Piatt County, Illinois | 432,000438,000 |
|
| | Pinckneyville | Pinckneyville, Illinois | 316,000 |
|
| | Raccoon Creek | Clay County, Illinois | 300,000304,000 |
|
| | Meramec(b)(d)(e) | St. Louis County, Missouri | 283,000281,000 |
|
| | Kinmundy(d) | Kinmundy, Illinois | 208,000 |
|
| | Peno Creek(c)(d) | Bowling Green, Missouri | 188,000 |
|
| Kirksville | Kirksville, Missouri | 13,000192,000 |
|
| Total natural gas | | | 2,828,0002,838,000 |
|
| Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 8,000 |
|
| Solar | O'FallonO’Fallon | O'Fallon,O’Fallon, Missouri | 3,000 |
|
| Total Ameren and Ameren Missouri | | | 10,235,00010,252,000 |
|
| |
| (a) | Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid. |
| |
| (b) | All coal-fueled kilowatts and 238,000236,000 natural-gas-fueled kilowatts at the Meramec energy center are scheduled for retirement in 2022. |
| |
| (c) | There are economic development lease arrangements applicable to these CTs. |
| |
| (d) | These CTs have the capability to operate on either oil or natural gas (dual fuel). |
| |
| (e) | Two of theits three units included here are steam-powered units.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, 2016:2017:
| | | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois |
Circuit miles of electric transmission lines(a) | 2,970 |
| | 4,619 |
| 2,970 |
| | 4,638 |
|
| Circuit miles of electric distribution lines | 33,346 |
| | 45,897 |
| 33,414 |
| | 45,899 |
|
| Percentage of circuit miles of electric distribution lines underground | 23 | % | | 15 | % | 23 | % | | 15 | % |
| Miles of natural gas transmission and distribution mains | 3,357 |
| | 18,364 |
| 3,379 |
| | 18,393 |
|
| 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 147303 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 center reservoir, certain facilities at Ameren Missouri’s Sioux energy center, most of Ameren Missouri’s Peno Creek and Audrain CT energy centers, Ameren Missouri'sMissouri’s Maryland Heights energy center, 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 center is located.
Substantially all of the properties and plant of Ameren Missouri and Ameren Illinois are subject to the first liens of the indentures securing their mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek CT energy center to the city of Bowling Green, Missouri, and leased the energy center back from the city through 2022. Under the terms of this capital lease, 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, at which time the property, plant, and equipment will become subject to the lien of any Ameren Missouri first mortgage bond indenture then in effect.
Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as lessee of the CT energy center under a long-term lease with Audrain County. The lease will expire in December 2023. Under the terms of this capital lease, 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, at which time the property, plant, and equipment will become subject to the lien of any Ameren Missouri first mortgage bond indenture then in effect.
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 109 – Callaway Energy Center, and Note 1514 – Commitments and Contingencies under Part II, Item 8, of this report and are incorporated herein by reference, include the following:
the unanimous stipulation and agreement between Ameren Missouri,Missouri’s proceeding with the MoPSC staff,to investigate how the MoOPC, and all intervenors, which is subject to MoPSC approval, that settleseffect of the July 2016 electric rate case;
ATXI’s lawsuits filed in October 2016reduction in the circuit courtsfederal 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 each of Adair, Knox, Marion, Schuyler, and Shelby counties in Missouri to obtain assents for road crossingsthe reduction in the counties wherefederal statutory corporate income tax rate enacted under the Mark TwainTCJA;
Ameren Illinois’ natural gas regulatory rate review filed with the ICC in January 2018;
the request filed by MISO participants, including Ameren Illinois and ATXI, with the FERC to allow revisions to 2018 electric transmission project will be constructed;rates to reflect the impacts of the reduction in the federal statutory corporate income tax rate enacted under the TCJA;
the February 2015 complaint case filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff;
litigation against Ameren Missouri relatedwith respect to the EPA Clean Air Act; and
remediation matters associated with former MGP and waste disposal sites of the Ameren Companies; and
the class action lawsuit against Ameren Missouri relating to municipal taxes.Companies.
| |
| ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 20162017, all their positions and offices held with the Ameren Companies as of February 15, 2017, tenure2018, their tenures as officer,officers, and their business backgroundbackgrounds 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 | 5556 |
| | Chairman, President and Chief Executive Officer, and Director |
Baxter joined Ameren Missouri in 1995. BaxterHe 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, Baxterhe was elected chairman, president and chief executive officer of Ameren Missouri. In February 2014, Baxterhe was elected chairman, president, and chief executive officer of Ameren, and was appointed to the Ameren board. In April 2014, he relinquished his positions at Ameren Missouri and was elected chief executive officer of Ameren. In July 2014, Baxter was elected chairman of the Ameren board.Missouri. |
| | | | |
| Martin J. Lyons, Jr. | 5051 |
| | Executive Vice President and Chief Financial Officer |
Lyons joined Ameren Services in 2001. In 2008, Lyonshe was elected senior vice president and chief accounting officer of the Ameren Companies. In 2009, Lyonshe was also elected chief financial officer of the Ameren Companies. In 2013, Lyonshe was elected executive vice president and chief financial officer of the Ameren Companies, and relinquished his duties as chief accounting officer. In 2016, Lyonshe was elected chairman and president of Ameren Services. |
| | | | |
| Gregory L. Nelson | 5960 |
| | Senior Vice President, General Counsel, and Secretary |
Nelson joined Ameren Missouri in 1995. NelsonHe was elected vice president and tax counsel of Ameren Services in 1999 and vice president of Ameren Missouri and Ameren Illinois in 2003. In 2010, Nelsonhe was elected vice president, tax and deputy general counsel of Ameren Services. He remained vice president of Ameren Missouri and Ameren Illinois. In 2011, Nelsonhe was elected senior vice president, general counsel and secretary of the Ameren Companies. |
| | | | |
| Bruce A. Steinke | 5556 |
| | 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, Steinkehe relinquished his positions at Ameren Illinois. In 2013, Steinkehe was elected senior vice president, finance, and chief accounting officer of the Ameren Companies. |
SUBSIDIARIES:
|
| | | | |
| Name | Age | | Positions and Offices Held |
| Mark C. Birk | 5253 |
| | Senior Vice President, Customer and Power Operations (Ameren Missouri) |
Birk joined Ameren Missouri in 1986. In 2005, Birkhe was elected vice president, power operations, of Ameren Missouri. In 2012, Birkhe 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, Birkhe was elected senior vice president, customer operations, at Ameren Missouri and relinquished his positions at Ameren Services. |
| | | |
Maureen A. Borkowski | 59 |
| | Chairman and President (ATXI) |
Borkowski joined Ameren Missouri in 1981. She left the company in 2000 and rejoined Ameren in 2005 as vice president, transmission, of Ameren Services. In 2011, BorkowskiOctober 2017, he was elected chairman and president of ATXI. In 2011, she was also elected senior vice president, transmission, ofcustomer and power operations, at Ameren Services.Missouri. |
| | | | |
| Fadi M. Diya | 5455 |
| | Senior Vice President and Chief Nuclear Officer (Ameren Missouri) |
Diya joined Ameren Missouri in 2005. In 2008, Diyahe was elected vice president, nuclear operations, of Ameren Missouri. In January 2014, Diyahe was elected senior vice president and chief nuclear officer of Ameren Missouri. |
| | | | |
| Mary P. Heger | 6061 |
| | Senior Vice President and Chief Information Officer (Ameren Services) |
Heger joined Ameren Missouri in 1976. In 2009, Hegershe was elected vice president, information technology, of Ameren Services, and in 2012, she was also elected chief information officer of Ameren Services. In 2015, Hegershe was elected senior vice president and chief information officer of Ameren Services. |
| | | | |
| Mark C. Lindgren | 4950 |
| | Senior Vice President, Corporate Communications and Chief Human Resources Officer (Ameren Services) |
Lindgren joined Ameren Services in 1998. In 2009, Lindgrenhe was elected vice president, human resources, of Ameren Services, and in 2012, he was also elected chief human resources officer of Ameren Services. In 2015, Lindgrenhe was elected senior vice president, corporate communications, and chief human resources officer of Ameren Services. |
| | | | |
| Richard J. Mark | 6162 |
| | Chairman and President (Ameren Illinois) |
Mark joined Ameren Services in 2002. He2002 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 2005.Missouri. In 2007, he relinquished his position at Ameren Services. In 2012, Markhe relinquished his position at Ameren Missouri and was elected chairman and president of Ameren Illinois. |
| | | | |
| Michael L. Moehn | 4748 |
| | Chairman and President (Ameren Missouri) |
Moehn joined Ameren Services in 2000. In 2004, he was elected vice president, corporate planning, of Ameren Services. In 2008, he was elected senior vice president, corporate planning and business risk management, of Ameren Services. In 2012, Moehnhe was elected senior vice president, customer operations, of Ameren Missouri.Missouri, and relinquished his position at Ameren Services. In April 2014, Moehnhe was elected chairman and president of Ameren Missouri. |
| | | |
| Shawn E. Schukar | 56 |
| | 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 of 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'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 49,98647,748 on January 31, 20172018. The following table presents the price ranges, closing prices, and dividends declared per Ameren common share for each quarter during 20162017 and 20152016:
| | | | High | | Low | | Close | | Dividends Declared | 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 |
| $ | 50.16 |
| | $ | 41.50 |
| | $ | 50.10 |
| | $ | 0.425 |
|
| June 30 | 53.59 |
| | 46.29 |
| | 53.58 |
| | 0.425 |
| 53.59 |
| | 46.29 |
| | 53.58 |
| | 0.425 |
|
| September 30 | 54.08 |
| | 47.79 |
| | 49.18 |
| | 0.425 |
| 54.08 |
| | 47.79 |
| | 49.18 |
| | 0.425 |
|
| December 31 | 52.88 |
| | 46.84 |
| | 52.46 |
| | 0.44 |
| 52.88 |
| | 46.84 |
| | 52.46 |
| | 0.44 |
|
| 2015 Quarter Ended: | | | | | | | | |
| March 31 | $ | 46.81 |
| | $ | 40.51 |
| | $ | 42.20 |
| | $ | 0.41 |
| |
| June 30 | 43.00 |
| | 37.26 |
| | 37.68 |
| | 0.41 |
| |
| September 30 | 43.85 |
| | 37.55 |
| | 42.27 |
| | 0.41 |
| |
| December 31 | 44.71 |
| | 41.33 |
| | 43.23 |
| | 0.425 |
| |
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 20162017 and 20152016:
| | | | 2016 | | 2015 | 2017 | | 2016 |
| (In millions) | Quarter Ended | | Quarter Ended | Quarter Ended | | Quarter Ended |
| Registrant | December 31 | | September 30 | | June 30 | | March 31 | | | December 31 | | September 30 | | June 30 | | March 31 | December 31 | | September 30 | | June 30 | | March 31 | | | December 31 | | September 30 | | June 30 | | March 31 |
| Ameren Missouri | $ | 70 |
| | $ | 75 |
| | $ | 70 |
| | $ | 140 |
| | | $ | 85 |
| | $ | 75 |
| | $ | 100 |
| | $ | 315 |
| $ | 30 |
| | $ | 160 |
| | $ | 112 |
| | $ | 60 |
| | | $ | 70 |
| | $ | 75 |
| | $ | 70 |
| | $ | 140 |
|
| Ameren Illinois | 15 |
| | 35 |
| | 30 |
| | 30 |
| | | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | | 15 |
| | 35 |
| | 30 |
| | 30 |
|
| Ameren | 107 |
| | 103 |
| | 103 |
| | 103 |
| | | 104 |
| | 99 |
| | 100 |
| | 99 |
| 111 |
| | 106 |
| | 107 |
| | 107 |
| | | 107 |
| | 103 |
| | 103 |
| | 103 |
|
On February 10, 2017,9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 4445.75 cents per share. The common share dividend is payable March 31, 2017,29, 2018, to shareholders of record on March 14, 2017.2018.
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, 2016 | — |
| | $ | — |
| | — |
| | — |
|
November 1 – November 30, 2016 (a) | 5,152 |
| | 49.11 |
| | — |
| | — |
|
December 1 – December 31, 2016 | — |
| | — |
| | — |
| | — |
|
| Total | 5,152 |
| | $ | 49.11 |
| | — |
| | — |
|
|
| | | | | | | | | | | | |
| 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) | SharesThe shares of Ameren common stock were purchased in open-market transactions pursuant to the 2014 Incentive Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards.awards issued under its stock-based compensation plans. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
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, 20162017, to December 31, 20162017.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 20162017. 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 in the United States. The comparison assumes that $100 was invested on December 31, 20112012, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
| | | December 31, | 2011 | | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| Ameren (AEE) | $ | 100.00 |
| | $ | 97.47 |
| | $ | 120.19 |
| | $ | 159.53 |
| | $ | 155.75 |
| | $ | 195.71 |
| $ | 100.00 |
| | $ | 123.31 |
| | $ | 163.67 |
| | $ | 159.79 |
| | $ | 200.79 |
| | $ | 232.84 |
|
| S&P 500 Index | 100.00 |
| | 116.00 |
| | 153.57 |
| | 174.60 |
| | 177.01 |
| | 198.18 |
| 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
| EEI Index | 100.00 |
| | 102.09 |
| | 115.37 |
| | 148.73 |
| | 142.93 |
| | 167.85 |
| 100.00 |
| | 113.01 |
| | 145.68 |
| | 140.00 |
| | 164.42 |
| | 183.69 |
|
Ameren management cautions that the stock price performance shown above should not be considered indicative of potential future stock price performance.
| |
| ITEM 6. | SELECTED FINANCIAL DATA |
| | For the years ended December 31, (In millions, except per share amounts) | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Ameren(a): | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 6,076 |
| | $ | 6,098 |
| | $ | 6,053 |
| | $ | 5,838 |
| | $ | 5,781 |
| $ | 6,177 |
| | $ | 6,076 |
| | $ | 6,098 |
| | $ | 6,053 |
| | $ | 5,838 |
|
Operating income(b) | 1,381 |
| | 1,259 |
| | 1,254 |
| | 1,184 |
| | 1,188 |
| 1,458 |
| | 1,381 |
| | 1,259 |
| | 1,254 |
| | 1,184 |
|
Income from continuing operations | 659 |
| | 585 |
| | 593 |
| | 518 |
| | 522 |
| 529 |
| | 659 |
| | 585 |
| | 593 |
| | 518 |
|
Income (loss) from discontinued operations, net of taxes(c)(d) | — |
| | 51 |
| | (1 | ) | | (223 | ) | | (1,496 | ) | — |
| | — |
| | 51 |
| | (1 | ) | | (223 | ) |
| Net income (loss) attributable to Ameren common shareholders | 653 |
| | 630 |
| | 586 |
| | 289 |
| | (974 | ) | |
| Net income attributable to Ameren common shareholders | | 523 |
| | 653 |
| | 630 |
| | 586 |
| | 289 |
|
| Common stock dividends | 416 |
| | 402 |
| | 390 |
| | 388 |
| | 382 |
| 431 |
| | 416 |
| | 402 |
| | 390 |
| | 388 |
|
| Continuing operations earnings per share – basic | 2.69 |
| | 2.39 |
| | 2.42 |
| | 2.11 |
| | 2.13 |
| 2.16 |
| | 2.69 |
| | 2.39 |
| | 2.42 |
| | 2.11 |
|
| Continuing operations earnings per share – diluted | 2.68 |
| | 2.38 |
| | 2.40 |
| | 2.10 |
| | 2.13 |
| 2.14 |
| | 2.68 |
| | 2.38 |
| | 2.40 |
| | 2.10 |
|
| Common stock dividends per share | 1.715 |
| | 1.655 |
| | 1.61 |
| | 1.60 |
| | 1.60 |
| 1.778 |
| | 1.715 |
| | 1.655 |
| | 1.61 |
| | 1.60 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
Total assets(d)(e) | $ | 24,699 |
| | $ | 23,640 |
| | $ | 22,289 |
| | $ | 20,907 |
| | $ | 22,022 |
| $ | 25,945 |
| | $ | 24,699 |
| | $ | 23,640 |
| | $ | 22,289 |
| | $ | 20,907 |
|
| Long-term debt, excluding current maturities | 6,595 |
| | 6,880 |
| | 6,085 |
| | 5,475 |
| | 5,765 |
| 7,094 |
| | 6,595 |
| | 6,880 |
| | 6,085 |
| | 5,475 |
|
| Total Ameren Corporation shareholders’ equity | 7,103 |
| | 6,946 |
| | 6,713 |
| | 6,544 |
| | 6,616 |
| 7,184 |
| | 7,103 |
| | 6,946 |
| | 6,713 |
| | 6,544 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 3,523 |
| | $ | 3,609 |
| | $ | 3,553 |
| | $ | 3,541 |
| | $ | 3,272 |
| $ | 3,539 |
| | $ | 3,523 |
| | $ | 3,609 |
| | $ | 3,553 |
| | $ | 3,541 |
|
Operating income(b) | 745 |
| | 742 |
| | 785 |
| | 803 |
| | 845 |
| 747 |
| | 745 |
| | 742 |
| | 785 |
| | 803 |
|
Net income available to common shareholder | 357 |
| | 352 |
| | 390 |
| | 395 |
| | 416 |
| 323 |
| | 357 |
| | 352 |
| | 390 |
| | 395 |
|
| Dividends to parent | 355 |
| | 575 |
| | 340 |
| | 460 |
| | 400 |
| 362 |
| | 355 |
| | 575 |
| | 340 |
| | 460 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 14,035 |
| | $ | 13,851 |
| | $ | 13,474 |
| | $ | 12,867 |
| | $ | 12,998 |
| $ | 14,043 |
| | $ | 14,035 |
| | $ | 13,851 |
| | $ | 13,474 |
| | $ | 12,867 |
|
| Long-term debt, excluding current maturities | 3,563 |
| | 3,844 |
| | 3,861 |
| | 3,631 |
| | 3,782 |
| 3,577 |
| | 3,563 |
| | 3,844 |
| | 3,861 |
| | 3,631 |
|
| Total shareholders' equity | 4,090 |
| | 4,082 |
| | 4,052 |
| | 3,993 |
| | 4,054 |
| |
| Total shareholders’ equity | | 4,081 |
| | 4,090 |
| | 4,082 |
| | 4,052 |
| | 3,993 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 2,490 |
| | $ | 2,466 |
| | $ | 2,498 |
| | $ | 2,311 |
| | $ | 2,525 |
| $ | 2,528 |
| | $ | 2,490 |
| | $ | 2,466 |
| | $ | 2,498 |
| | $ | 2,311 |
|
| Operating income | 544 |
| | 466 |
| | 450 |
| | 415 |
| | 377 |
| 580 |
| | 544 |
| | 466 |
| | 450 |
| | 415 |
|
| Net income available to common shareholder | 252 |
| | 214 |
| | 201 |
| | 160 |
| | 141 |
| 268 |
| | 252 |
| | 214 |
| | 201 |
| | 160 |
|
| Dividends to parent | 110 |
| | — |
| | — |
| | 110 |
| | 189 |
| — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 9,474 |
| | $ | 8,903 |
| | $ | 8,204 |
| | $ | 7,397 |
| | $ | 7,186 |
| $ | 10,345 |
| | $ | 9,474 |
| | $ | 8,903 |
| | $ | 8,204 |
| | $ | 7,397 |
|
| Long-term debt, excluding current maturities | 2,338 |
| | 2,342 |
| | 2,224 |
| | 1,844 |
| | 1,566 |
| 2,373 |
| | 2,338 |
| | 2,342 |
| | 2,224 |
| | 1,844 |
|
| Total shareholders' equity | 3,034 |
| | 2,897 |
| | 2,661 |
| | 2,448 |
| | 2,401 |
| |
| Total shareholders’ equity | | 3,310 |
| | 3,034 |
| | 2,897 |
| | 2,661 |
| | 2,448 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | Includes a $69 million provision recorded in 2015 for all of the previously capitalized COL costs relating to the cancelled second nuclear unit at its existing Callaway 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. |
| |
(d)(e) | Includes total assets from discontinued operations of $15 million, $14 million, $15 million, $165 million, and $1,611 million at December 31, 2013, and immaterial balances at December 31, 2017, 2016, 2015, 2014, 2013, and 2012, respectively.2014. Total assets from discontinued operations are included in “Other current assets” on Ameren’s balance sheet. |
| |
| ITEM 7. | MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. Ameren’swhose primary assets are its equity interests in its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. 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'sAmeren’s principal subsidiaries.subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has various other subsidiaries that conduct other activities, such as the provision of 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 distribution,transmission, electric transmissiondistribution, 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 Spoon River, and Mark Twain projects. ATXIprojects, 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 also evaluating competitiveprimarily composed of the aggregated electric transmission investment opportunities outsidebusinesses of MISO as they arise.Ameren Illinois and ATXI. See Note 15 – 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'sManagement’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'sAmeren’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. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding for the relevant period.
OVERVIEW
Ameren’s strategic plan includes investing in, 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 2016, Ameren successfully executed its strategy.2017, Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks. In 2016, AmerenIt invested $1.3$1.4 billion of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.
In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The electric rate order resulted in a $92 million increase in Ameren continuedMissouri’s revenue requirement, a $54 million decrease in the base level of net energy costs, and a $26 million reduction in the base level of certain tracked expenses, compared with the amounts in the MoPSC’s April 2015 rate order. The new rates and base level of expenses became effective on April 1, 2017. 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 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 work to enhance its regulatory frameworkscustomer 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 advocate for responsibleadding 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 economic policies and to create and capitalize on opportunities for investment fora 50% reduction by 2040 from the benefit2005 level by retiring coal-fired generation at the end of its customers and shareholders.useful life.
In January 2017, Ameren Illinois successfully advocated forimplemented provisions of the FEJA whichthat improved the constructive regulatory framework for Ameren Illinois'of its electric distribution business. The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking process through 2022. Also, beginning in 2017, the FEJA decouplesdecoupled electric distribution revenues established in a rate proceeding from actual sales volumes by providingvolumes. It provided that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes that are reflected in that year'syear’s rates will be collected from, or refunded to, customers within two years. This portion of the law extends beyond the end of the IEIMA in 2022. Further, beginning as early asAlso, since June 2017, the FEJA will allowhas allowed Ameren Illinois to capitalizedefer the costs of its electric energy-efficiency program as a regulatory asset and earn a return on itsthose 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 yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy-efficiency program investments can also be increased or decreased by up to 200 basis points, depending on the achievement of annual energy efficiency investments.
savings goals. In July 2016,January 2018, Ameren MissouriIllinois filed a request with the MoPSCICC seeking approval to increase its annual revenues for electric service. Relating tonatural gas delivery service by $49 million, which included an estimated $42 million of annual revenues that request, in February 2017, Ameren Missouri, the MoPSC staff, the MoOPC, and all intervenors filedwould otherwise be recovered under a unanimous stipulation and agreement with the MoPSC. The stipulation and agreement, which is subject to MoPSC approval, would result in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate order. The stipulation and agreement did not specify the common equity percentage, the rate base, or the allowed return on common equity. The new revenue requirement reflects the current actual sales volumes of the New Madrid Smelter, whose operations remain suspended, as well as other agreed upon sales volumes. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs under the stipulation and agreement would decrease 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, would reduce expenses by $26 million from the base levels established in the MoPSC's April 2015 electric rate order.QIP rider. The stipulation and agreement contemplates that new rates will become effectiverequest was based on or before March 20, 2017.
Related to ATXI's and Ameren Illinois' FERC rate-regulated transmission businesses, in September 2016, the FERC issued a final order in the November 2013 complaint case which lowered the total allowed10.3% return on common equity, to 10.82%. The new
allowed return ona capital structure composed of 50% common equity, has been reflectedand a rate base of $1.6 billion.
In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with Ameren Missouri and an electric cooperative in rates prospectivelynortheast Missouri to locate almost all of the Mark Twain project on existing line corridors. It also received assents for road crossings from the September 2016 effective datefive affected counties in northeast Missouri. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the order. The FERC is expectedMark Twain project. ATXI plans to issue a final order in the February 2015 complaint casebegin construction in the second quarter of 2017. That final order will determine2018 and to complete the allowed return on common equity forproject by the 15-month period ended May 2016. That final order will also establish the allowed return on common equity that will apply prospectively from its expected second quarter 2017 effective date, replacing the current 10.82% total return on common equity, which became effective in September 2016.end of 2019.
In October 2016,2017, Ameren’s board of directors increased the quarterly common stock dividend to 4445.75 cents per share, resulting in an annualized equivalent dividend rate of $1.76$1.83 per share.
Earnings
Net income attributable to Ameren common shareholders from continuing operations was $523 million, or $2.14 per diluted share, for 2017, and $653 million, or $2.68 per diluted share, for 2016. Net income was unfavorably affected in 2017, compared with 2016, by increased income tax expense due to a noncash charge to earnings for the revaluation of deferred taxes primarily at Ameren (parent) as a result of the TCJA and $579 million, or $2.38 per diluted share, for 2015. These earningsthe increase in the Illinois income tax rate. Earnings were also unfavorably affected in 2017, compared with 2016, by decreased demand, primarily 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 2016,2017, compared with 2015,2016, 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 Ameren Transmission andinvestments in infrastructure at the Ameren Illinois Electric Distribution earnings, reflectingand Ameren Transmission segments, which reflect Ameren’s strategy to allocate incremental capital to those businesses, increased demand due to warmer summer temperatures, higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order, and decreased other operations and maintenance expenses. Net income was also favorably affected in 2016, compared with 2015, by an income tax benefit recorded in 2016 at Ameren (parent) pursuant tobusinesses.
After the adoptionapplication of new accounting guidance related to share-based compensation, as well asjurisdictional regulatory recovery mechanisms, the absenceeffect of a provision recognized in 2015the revaluation of deferred taxes as a result of the TCJA was a decrease to Ameren’s and Ameren Missouri’s discontinued efforts to licensenet income of $154 million and build a second nuclear unit at its existing Callaway energy center site. Net$36 million, respectively, while the effect on Ameren Illinois’ net income was unfavorably affected in 2016, compared with 2015, by the absence in 2016 of MEEIA 2013 net shared benefits, partially offset by the recognition of a MEEIA 2013 performance incentive, decreased Ameren Missouri sales to the New Madrid Smelter resulting from a reduction in operations at that plant, and the cost of the Callaway energy center’s scheduled refueling and maintenance outage. Additionally, earnings were unfavorably affected in 2016, compared with 2015, by increased depreciation and amortization expenses at Ameren Missouri, the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism, and decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues.immaterial.
Liquidity
At December 31, 2016,2017, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under credit agreementsthe Credit Agreements of $1.5$1.6 billion.
Capital Expenditures
In 2016,2017, Ameren continued to make significant investment in its utility businesses by making capital expenditures of $0.7$0.8 billion, $0.5 billion, $0.2 billion, and $0.7$0.6 billion in Ameren
Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. For 20172018 through 2021, Ameren's2022, Ameren’s cumulative capital expenditures are projected to range from $10.4$10.5 billion to $11.2$11.4 billion. The projected spending by segment includes up to $4.2$4.5 billion, $2.6$2.5 billion, $1.5$1.7 billion, and $2.9$2.7 billion for Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively.
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Weather, economicEconomic conditions, energy efficiencyenergy-efficiency investments by our customers and by us, and the actions of key customers can significantly affect the demand for our services. OurAmeren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands. Ameren and Ameren Missouri are also affecteddemands, 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 prices we charge for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, with regulatorywithin the frameworks established by our regulators.
Ameren Missouri principally uses coal, nuclear fuel, and natural gas 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. WeAs described below, we 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'Illinois’ electric distribution service business, and a FAC for Ameren Missouri'sMissouri’s electric utility business.
Ameren Illinois' electric distribution service utility business, pursuantMissouri’s FAC cost recovery mechanism allows it to the IEIMA, conducts an annual reconciliationrecover 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 requirement necessaryis offset by a corresponding change in fuel expense to reflectreduce 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 in a given year with the revenue requirementand costs included in customer rates for that year. Recoveries fromas a regulatory asset or refunds to customers occurregulatory liability. The difference will be reflected in base rates in a subsequent year. IncludedMoPSC 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'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 reconciliation is a formula for theand allowed return on equity, whichunder 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'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 United States Treasurysuch 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 rate formula ratemaking framework in setting their transmission rates. These rates are updated each January with forecasted information. A reconciliation duringIf a given year’s revenue requirement varies from the year, which adjusts for theamount 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 and actual sales volumes,requirement. The regulatory balance is usedcollected from, or refunded to, adjust billing rates in a subsequent year.
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 Ameren Illinois’ electric distribution service business operateis subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under formula ratemaking designed to providePart II, Item 8, of this report for the recovery of actual costs of service that are prudently incurred as well as a return on equity. Although rate-regulated, Ameren Illinois’ natural gas business and Ameren Missouri do not operate under formula ratemaking. Ameren (parent) is not rate-regulated.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'sMissouri’s energy centers and our transmission and distribution systems and the level and timing of purchased power costs, 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.
During
Earnings Summary
The following table presents a summary of Ameren’s earnings for the fourth quarteryears ended December 31, 2017, 2016, and 2015: |
| | | | | | | | | | | |
| | 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
Net income attributable to Ameren common shareholders from continuing operations in 2017 decreased $130 million, or $0.54 per diluted share, from 2016. The decrease was due to an increase in net loss of 2016,$125 million for activity not reported as part of a segment, primarily at Ameren (parent), and a net income decrease of $34 million at Ameren Missouri, both of which 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 from Ameren Companies changed the manner in which performance is assessedTransmission and resources are allocated, driven by increasing investment in FERC-regulated electric transmission and Ameren Illinois electric distribution and natural gas distribution businesses, as well as the unique regulatory environment for each jurisdiction. Ameren now has four segments: Ameren Missouri, 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, primarily at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decrease in the federal statutory corporate income tax rate resulting from enactment of the TCJA (63 cents per share), and an increase in the Illinois Natural Gas, and Ameren Transmission, whichcorporate income tax rate (6 cents per share), as discussed in Note 12 – Income Taxes under Part II, Item 8, of this report;
decreased demand primarily includes Ameren Illinois Transmission and ATXI.at Ameren Missouri has one segment, which includesdue to milder winter and summer temperatures in 2017 (estimated at 15 cents per share);
the absence in 2017 of a MEEIA 2013 performance incentive at Ameren Missouri recognized in 2016 (7 cents per share);
increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri resulting from 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. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas,Missouri pursuant to the MoPSC’s March 2017 electric rate order as discussed in Note 2 – Rate and Ameren Illinois Transmission. Prior-period presentation has been adjusted for comparative purposes. See Note 16 – Segment InformationRegulatory 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 further discussion of Ameren’s, Ameren Missouri's,charitable contributions, tax benefits related to company-owned life insurance, and Ameren Illinois' segments.
Earnings Summarytax 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 following table presents a summarycents per share information presented above is based on the diluted average shares outstanding in 2016. Pretax amounts have been presented net of Ameren's earnings for the years ended December 31,income taxes, using Ameren’s 2016 2015, and 2014:
|
| | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| Net income attributable to Ameren common shareholders | $ | 653 |
| | $ | 630 |
| | $ | 586 |
|
| Earnings per common share – diluted | 2.68 |
| | 2.59 |
| | 2.40 |
|
| Net income attributable to Ameren common shareholders – continuing operations | 653 |
| | 579 |
| | 587 |
|
| Earnings per common share – diluted – continuing operations | 2.68 |
| | 2.38 |
| | 2.40 |
|
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 the second quarter of 2015, as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing 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'scenter’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'scenter’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 because ofresulting from additional electric system capital additionsproperty, plant, and equipment (4 cents per share);
decreased Ameren Illinois Electric Distribution earnings resulting from the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share);
decreased 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 (2 cents per share).
The cents per share information presented above is based on the diluted average shares outstanding in 2015. Pretax amounts have been presented net of income taxes, using Ameren'sAmeren’s 2015 statutory tax rate of 39%.
2015 versus 2014
Net income attributable to Ameren common shareholders from continuing operations in 2015 decreased $8 million, or $0.02 per diluted share, from 2014. The decrease was due to a $38 million and a $13 million decrease in net income from Ameren Missouri and Ameren Illinois Natural Gas, respectively. The decrease was partially offset by a $32 million and a $10 million increase in net income from Ameren Transmission and Ameren Illinois Electric Distribution, respectively.
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 2014, 2015 earnings per share from continuing operations were unfavorably affected by:
a provision recognized in the second quarter of 2015 as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site (18 cents per share);
decreased electric and natural gas sales volumes, primarily due to warmer winter temperatures in 2015 (estimated at 6 cents per share);
increased net financing costs at Ameren Missouri, primarily due to a reduction in allowance for funds used during construction as multiple significant electric capital projects were completed in 2014 (6 cents per share);
increased depreciation and amortization expenses at Ameren Illinois Natural Gas, resulting from amortization of
capital additions, and at Ameren Missouri, primarily resulting from electric capital additions completed in 2014 which were not reflected in customer rates until May 30, 2015 (5 cents per share); and
the absence in 2015 of a recovery of certain previously disallowed debt premium costs per the ICC's December 2014 order (3 cents per share).
Compared with 2014, 2015 earnings per share from continuing operations were favorably affected by:
increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment (15 cents per share). These earnings were reduced by an estimate of the probable customer refunds as a result of the FERC complaint cases regarding the allowed return on common equity (3 cents per share);
increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment as well as interest earned on the revenue requirement reconciliation adjustment regulatory assets (5 cents per share), partially offset by a lower return on equity due to a reduction in the 30-year United States Treasury bond yields (2 cents per share);
the absence of a Callaway energy center scheduled refueling and maintenance outage in 2015, partially offset by preparation costs incurred in 2015 for the 2016 scheduled refueling outage (7 cents per share);
increased Ameren Illinois Electric Distribution earnings resulting from a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share);
excluding the scheduled refueling and maintenance outage, MEEIA program costs, and expenses with corresponding increases in electric revenues resulting from the April 2015 MoPSC electric rate order, decreased other operations and maintenance expenses at Ameren Missouri primarily because of decreased energy center costs and at other businesses (4 cents per share); and
decreased interest expense attributable to other businesses, primarily due to Ameren's (parent) maturity of higher-cost debt in 2014 being replaced with lower-cost debt in 2015 (4 cents per share).
The cents per share information presented above is based on the diluted average shares outstanding in 2014. Pretax amounts have been presented net of income taxes, using Ameren's 2014 statutory tax rate of 39%.
For additional details regarding the Ameren Companies’ segment results of operations, including explanations of 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, Interest Charges, Income Taxes, and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.
Below is Ameren'sAmeren’s table of income statement components by segment for the years ended December 31, 2017, 2016, 2015, and 2014:2015:
| | | 2017 | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other / Intersegment Eliminations | | Total |
| Electric margins | | $ | 2,431 |
| | $ | 1,109 |
| | $ | — |
| | $ | 426 |
| | $ | (31 | ) | | $ | 3,935 |
|
| Natural gas margins | | 79 |
| | — |
| | 479 |
| | — |
| | (2 | ) | | 556 |
|
| Other revenues | | — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | — |
|
| Other operations and maintenance | | (902 | ) | | (512 | ) | | (224 | ) | | (63 | ) | | 41 |
| | (1,660 | ) |
| Depreciation and amortization | | (533 | ) | | (239 | ) | | (59 | ) | | (60 | ) | | (5 | ) | | (896 | ) |
| Taxes other than income taxes | | (328 | ) | | (74 | ) | | (60 | ) | | (6 | ) | | (9 | ) | | (477 | ) |
| Other income and (expenses) | | 40 |
| | 3 |
| | (3 | ) | | 1 |
| | (3 | ) | | 38 |
|
| Interest charges | | (207 | ) | | (73 | ) | | (36 | ) | | (67 | ) | | (8 | ) | | (391 | ) |
| Income taxes | | (254 | ) | | (83 | ) | | (36 | ) | | (90 | ) | | (113 | ) | | (576 | ) |
| Net income (loss) | | 326 |
| | 132 |
| | 61 |
| | 141 |
| | (131 | ) |
| 529 |
|
| Noncontrolling interests – preferred stock dividends | | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | | $ | 323 |
| | $ | 131 |
| | $ | 60 |
| | $ | 140 |
| | $ | (131 | ) | | $ | 523 |
|
| 2016 | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other / Intersegment Eliminations | | Total | | | | | | | | | | | |
| Electric margins | $ | 2,397 |
| | $ | 1,105 |
| | $ | — |
| | $ | 355 |
| | $ | (27 | ) | | $ | 3,830 |
| $ | 2,397 |
| | $ | 1,105 |
| | $ | — |
| | $ | 355 |
| | $ | (27 | ) | | $ | 3,830 |
|
| Natural gas margins | 79 |
| | — |
| | 462 |
| | — |
| | (2 | ) | | 539 |
| 79 |
| | — |
| | 462 |
| | — |
| | (2 | ) | | 539 |
|
| Other revenues | 1 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| 1 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
|
| Other operations and maintenance | (893 | ) | | (538 | ) | | (215 | ) | | (60 | ) | | 30 |
| | (1,676 | ) | (893 | ) | | (538 | ) | | (215 | ) | | (60 | ) | | 30 |
| | (1,676 | ) |
| Depreciation and amortization | (514 | ) | | (226 | ) | | (55 | ) | | (43 | ) | | (7 | ) | | (845 | ) | (514 | ) | | (226 | ) | | (55 | ) | | (43 | ) | | (7 | ) | | (845 | ) |
| Taxes other than income taxes | (325 | ) | | (72 | ) | | (58 | ) | | (4 | ) | | (8 | ) | | (467 | ) | (325 | ) | | (72 | ) | | (58 | ) | | (4 | ) | | (8 | ) | | (467 | ) |
| Other income and (expenses) | 42 |
| | 8 |
| | (1 | ) | | 2 |
| | (9 | ) | | 42 |
| 42 |
| | 8 |
| | (1 | ) | | 2 |
| | (9 | ) | | 42 |
|
| Interest charges | (211 | ) | | (72 | ) | | (34 | ) | | (58 | ) | | (7 | ) | | (382 | ) | (211 | ) | | (72 | ) | | (34 | ) | | (58 | ) | | (7 | ) | | (382 | ) |
| Income taxes | (216 | ) | | (78 | ) | | (39 | ) | | (74 | ) | | 25 |
| | (382 | ) | (216 | ) | | (78 | ) | | (39 | ) | | (74 | ) | | 25 |
| | (382 | ) |
| Income (loss) from continuing operations | 360 |
| | 127 |
| | 60 |
| | 118 |
| | (6 | ) | | 659 |
| |
| Income from discontinued operations, net of taxes | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Net income (loss) | 360 |
| | 127 |
| | 60 |
| | 118 |
| | (6 | ) |
| 659 |
| 360 |
|
| 127 |
| | 60 |
| | 118 |
| | (6 | ) | | 659 |
|
| 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 |
| $ | 357 |
| | $ | 126 |
| | $ | 59 |
| | $ | 117 |
| | $ | (6 | ) |
| $ | 653 |
|
| 2015 | | | | | | | | | | | | | | | | | | | | | | |
| Electric margins | $ | 2,481 |
| | $ | 1,074 |
| | $ | — |
| | $ | 259 |
| | $ | (26 | ) | | $ | 3,788 |
| $ | 2,481 |
| | $ | 1,074 |
| | $ | — |
| | $ | 259 |
| | $ | (26 | ) | | $ | 3,788 |
|
| Natural gas margins | 80 |
| | — |
| | 425 |
| | — |
| | (2 | ) | | 503 |
| 80 |
| | — |
| | 425 |
| | — |
| | (2 | ) | | 503 |
|
| Other revenues | 2 |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| 2 |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
|
| Other operations and maintenance | (925 | ) | | (532 | ) | | (219 | ) | | (56 | ) | | 38 |
| | (1,694 | ) | (925 | ) | | (532 | ) | | (219 | ) | | (56 | ) | | 38 |
| | (1,694 | ) |
| Provision for Callaway construction and operating license | (69 | ) | | — |
| | — |
| | — |
| | — |
| | (69 | ) | (69 | ) | | — |
| | — |
| | — |
| | — |
| | (69 | ) |
| Depreciation and amortization | (492 | ) | | (212 | ) | | (52 | ) | | (33 | ) | | (7 | ) | | (796 | ) | (492 | ) | | (212 | ) | | (52 | ) | | (33 | ) | | (7 | ) | | (796 | ) |
| Taxes other than income taxes | (335 | ) | | (72 | ) | | (56 | ) | | (2 | ) | | (8 | ) | | (473 | ) | (335 | ) | | (72 | ) | | (56 | ) | | (2 | ) | | (8 | ) | | (473 | ) |
| Other income and (expenses) | 41 |
| | 8 |
| | (1 | ) | | 2 |
| | (6 | ) | | 44 |
| 41 |
| | 8 |
| | (1 | ) | | 2 |
| | (6 | ) | | 44 |
|
| Interest charges | (219 | ) | | (71 | ) | | (35 | ) | | (35 | ) | | 5 |
| | (355 | ) | (219 | ) | | (71 | ) | | (35 | ) | | (35 | ) | | 5 |
| | (355 | ) |
| Income taxes | (209 | ) | | (71 | ) | | (24 | ) | | (51 | ) | | (8 | ) | | (363 | ) | (209 | ) | | (71 | ) | | (24 | ) | | (51 | ) | | (8 | ) | | (363 | ) |
| Income (loss) from continuing operations | 355 |
| | 124 |
| | 38 |
| | 84 |
| | (16 | ) |
| 585 |
| 355 |
| | 124 |
| | 38 |
| | 84 |
| | (16 | ) |
| 585 |
|
| Income from discontinued operations, net of taxes | — |
| | — |
| | — |
| | — |
| | 51 |
| | 51 |
| — |
| | — |
| | — |
| | — |
| | 51 |
| | 51 |
|
| Net income | 355 |
|
| 124 |
| | 38 |
| | 84 |
| | 35 |
| | 636 |
| 355 |
| | 124 |
| | 38 |
| | 84 |
| | 35 |
| | 636 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income attributable to Ameren common shareholders | $ | 352 |
| | $ | 123 |
| | $ | 37 |
| | $ | 83 |
| | $ | 35 |
|
| $ | 630 |
| $ | 352 |
| | $ | 123 |
| | $ | 37 |
| | $ | 83 |
| | $ | 35 |
|
| $ | 630 |
|
| 2014 | | | | | | | | | | | | |
| Electric margins | $ | 2,436 |
| | $ | 1,025 |
| | $ | — |
| | $ | 187 |
| | $ | (22 | ) | | $ | 3,626 |
| |
| Natural gas margins | 82 |
| | — |
| | 443 |
| | — |
| | — |
| | 525 |
| |
| Other revenues | 1 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| |
| Other operations and maintenance | (939 | ) | | (507 | ) | | (220 | ) | | (49 | ) | | 31 |
| | (1,684 | ) | |
| Depreciation and amortization | (473 | ) | | (197 | ) | | (41 | ) | | (26 | ) | | (8 | ) | | (745 | ) | |
| Taxes other than income taxes | (322 | ) | | (73 | ) | | (63 | ) | | (2 | ) | | (8 | ) | | (468 | ) | |
| Other income and (expenses) | 48 |
| | 4 |
| | (1 | ) | | 6 |
| | — |
| | 57 |
| |
| Interest charges | (211 | ) | | (63 | ) | | (28 | ) | | (26 | ) | | (13 | ) | | (341 | ) | |
| Income (taxes) benefit | (229 | ) | | (75 | ) | | (39 | ) | | (38 | ) | | 4 |
| | (377 | ) | |
| Income (loss) from continuing operations | 393 |
| | 114 |
| | 51 |
| | 52 |
| | (17 | ) |
| 593 |
| |
| Loss from discontinued operations, net of taxes | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) | |
| Net income (loss) | 393 |
| | 114 |
| | 51 |
| | 52 |
| | (18 | ) | | 592 |
| |
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) | |
| Net income (loss) attributable to Ameren common shareholders | $ | 390 |
| | $ | 113 |
| | $ | 50 |
| | $ | 51 |
| | $ | (18 | ) |
| $ | 586 |
| |
Below is Ameren Illinois'Illinois’ table of income statement components by segment for the years ended December 31, 2017, 2016, 2015, and 2014:
| | | 2017 | | Electric Distribution | | Natural Gas | | Transmission | | Total |
| Electric margins | | $ | 1,109 |
| | $ | — |
| | $ | 258 |
| | $ | 1,367 |
|
| Natural gas margins | | — |
| | 479 |
| | — | | 479 |
|
| Other revenues | | 1 |
| | — |
| | — | | 1 |
|
| Other operations and maintenance | | (512 | ) | | (224 | ) | | (53 | ) | | (789 | ) |
| Depreciation and amortization | | (239 | ) | | (59 | ) | | (43 | ) | | (341 | ) |
| Taxes other than income taxes | | (74 | ) | | (60 | ) | | (3 | ) | | (137 | ) |
| Other income and (expenses) | | 3 |
| | (3 | ) | | 1 |
| | 1 |
|
| Interest charges | | (73 | ) | | (36 | ) | | (35 | ) | | (144 | ) |
| Income taxes | | (83 | ) | | (36 | ) | | (47 | ) | | (166 | ) |
| Net income | | 132 |
| | 61 |
| | 78 |
| | 271 |
|
| Preferred stock dividends | | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | | $ | 131 |
| | $ | 60 |
| | $ | 77 |
| | $ | 268 |
|
| 2016 | Electric Distribution | | Natural Gas | | Transmission | | Total | | | | | | | |
| Electric margins | $ | 1,105 |
| | $ | — |
| | $ | 232 |
| | $ | 1,337 |
| $ | 1,105 |
| | $ | — |
| | $ | 232 |
| | $ | 1,337 |
|
| Natural gas margins | — |
| | 462 |
| | — | | 462 |
| — | | 462 |
| | — | | 462 |
|
| Other operations and maintenance | (538 | ) | | (215 | ) | | (51 | ) | | (804 | ) | (538 | ) | | (215 | ) | | (51 | ) | | (804 | ) |
| Depreciation and amortization | (226 | ) | | (55 | ) | | (38 | ) | | (319 | ) | (226 | ) | | (55 | ) | | (38 | ) | | (319 | ) |
| Taxes other than income taxes | (72 | ) | | (58 | ) | | (2 | ) | | (132 | ) | (72 | ) | | (58 | ) | | (2 | ) | | (132 | ) |
| Other income and (expenses) | 8 |
| | (1 | ) | | 2 |
| | 9 |
| 8 |
| | (1 | ) | | 2 |
| | 9 |
|
| Interest charges | (72 | ) | | (34 | ) | | (34 | ) | | (140 | ) | (72 | ) | | (34 | ) | | (34 | ) | | (140 | ) |
| Income taxes | (78 | ) | | (39 | ) | | (41 | ) | | (158 | ) | (78 | ) | | (39 | ) | | (41 | ) | | (158 | ) |
| Net income | 127 |
| | 60 |
| | 68 |
| | 255 |
| 127 |
| | 60 |
| | 68 |
| | 255 |
|
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | $ | 126 |
| | $ | 59 |
| | $ | 67 |
| | $ | 252 |
| $ | 126 |
| | $ | 59 |
| | $ | 67 |
| | $ | 252 |
|
| 2015 | | | | | | | | | | | | | | |
| Electric margins | $ | 1,074 |
| | $ | — |
| | $ | 189 |
| | $ | 1,263 |
| $ | 1,074 |
| | $ | — |
| | $ | 189 |
| | $ | 1,263 |
|
| Natural gas margins | — | | 425 |
| | — | | 425 |
| — |
| | 425 |
| | — |
| | 425 |
|
| Other operations and maintenance | (532 | ) | | (219 | ) | | (46 | ) | | (797 | ) | (532 | ) | | (219 | ) | | (46 | ) | | (797 | ) |
| Depreciation and amortization | (212 | ) | | (52 | ) | | (31 | ) | | (295 | ) | (212 | ) | | (52 | ) | | (31 | ) | | (295 | ) |
| Taxes other than income taxes | (72 | ) | | (56 | ) | | (2 | ) | | (130 | ) | (72 | ) | | (56 | ) | | (2 | ) | | (130 | ) |
| Other income and (expenses) | 8 |
| | (1 | ) | | 2 |
| | 9 |
| 8 |
| | (1 | ) | | 2 |
| | 9 |
|
| Interest charges | (71 | ) | | (35 | ) | | (25 | ) | | (131 | ) | (71 | ) | | (35 | ) | | (25 | ) | | (131 | ) |
| Income taxes | (71 | ) | | (24 | ) | | (32 | ) | | (127 | ) | (71 | ) | | (24 | ) | | (32 | ) | | (127 | ) |
| Net income | 124 |
| | 38 |
| | 55 |
| | 217 |
| 124 |
| | 38 |
| | 55 |
| | 217 |
|
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | $ | 123 |
| | $ | 37 |
| | $ | 54 |
| | $ | 214 |
| $ | 123 |
| | $ | 37 |
| | $ | 54 |
| | $ | 214 |
|
| 2014 | | | | | | | | |
| Electric margins | $ | 1,025 |
| | $ | — |
| | $ | 154 |
| | $ | 1,179 |
| |
| Natural gas margins | — |
| | 443 |
| | — |
| | 443 |
| |
| Other operations and maintenance | (507 | ) | | (220 | ) | | (44 | ) | | (771 | ) | |
| Depreciation and amortization | (197 | ) | | (41 | ) | | (25 | ) | | (263 | ) | |
| Taxes other than income taxes | (73 | ) | | (63 | ) | | (2 | ) | | (138 | ) | |
| Other income and (expenses) | 4 |
| | (1 | ) | | 6 |
| | 9 |
| |
| Interest charges | (63 | ) | | (28 | ) | | (21 | ) | | (112 | ) | |
| Income taxes | (75 | ) | | (39 | ) | | (29 | ) | | (143 | ) | |
| Net income | 114 |
| | 51 |
| | 39 |
| | 204 |
| |
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | |
| Net income attributable to common shareholder | $ | 113 |
| | $ | 50 |
| | $ | 38 |
| | $ | 201 |
| |
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, as well as 2015 compared with 2014. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural gas purchased for resale.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 | | 2016 versus 2015 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren | |
| 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) | $ | 57 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 72 |
| $ | (65 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (70 | ) |
| Base rates (estimate) | 48 |
| | 38 |
| | — |
| | 102 |
| | — |
| | 188 |
| 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) | 7 |
| | — |
| | — |
| | — |
| | — |
| | 7 |
| (6 | ) | | — |
| | — |
| | — |
| | — |
| | (6 | ) |
| New Madrid Smelter revenues | (129 | ) | | — |
| | — |
| | — |
| | — |
| | (129 | ) | |
| Off-system sales and capacity revenues | 153 |
| | — |
| | — |
| | — |
| | — |
| | 153 |
| 22 |
| | — |
| | — |
| | — |
| | — |
| | 22 |
|
| MEEIA 2013 net shared benefits | (85 | ) | | — |
| | — |
| | — |
| | — |
| | (85 | ) | |
| MEEIA 2013 performance incentive | 28 |
| | — |
| | — |
| | — |
| | — |
| | 28 |
| (28 | ) | | — |
| | — |
| | — |
| | — |
| | (28 | ) |
| Transmission services revenues | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Purchased power rider order in 2015 | — |
| | (15 | ) | | — |
| | — |
| | — |
| | (15 | ) | |
| Other | (1 | ) | | (1 | ) | | — |
| | (6 | ) | | (21 | ) | | (29 | ) | 4 |
| | (1 | ) | | — |
| | — |
| | 5 |
| | 8 |
|
Cost recovery mechanisms – offset in fuel and purchased power:(c) | | | | | | | | | | | | |
| Power supply costs | — |
| | (28 | ) | | — |
| | — |
| | — |
| | (28 | ) | |
| Transmission services recovery mechanism | — |
| | 6 |
| | — |
| | — |
| | — |
| | 6 |
| |
| Recovery of FAC under-recovery | (118 | ) | | — |
| | — |
| | — |
| | — |
| | (118 | ) | |
Other cost recovery mechanisms:(d) | | | | | | | | | | | | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| |
| Gross receipts tax | (5 | ) | | — |
| | — |
| | — |
| | — |
| | (5 | ) | |
| MEEIA 2013 and 2016 program costs | (34 | ) | | — |
| | — |
| | — |
| | — |
| | (34 | ) | |
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 | $ | (76 | ) | | $ | 17 |
| | $ | — |
| | $ | 96 |
| | $ | (21 | ) | | $ | 16 |
| $ | 19 |
| | $ | 19 |
| | $ | — |
| | $ | 71 |
| | $ | 5 |
| | $ | 114 |
|
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | | |
| Energy costs (excluding the New Madrid Smelter and estimated effect of weather) | $ | (145 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (145 | ) | $ | (22 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (22 | ) |
| New Madrid Smelter energy costs | 72 |
| | — |
| | — |
| | — |
| | — |
| | 72 |
| |
Effect of weather (estimate)(b) | (9 | ) | | (8 | ) | | — |
| | — |
| | — |
| | (17 | ) | 13 |
| | (1 | ) | | — |
| | — |
| | — |
| | 12 |
|
| Effect of higher net energy costs included in base rates | (34 | ) | | — |
| | — |
| | — |
| | — |
| | (34 | ) | |
| Effect of lower net energy costs included in base rates | | 39 |
| | — |
| | — |
| | — |
| | — |
| | 39 |
|
| Transmission services charges | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) |
| Other | 6 |
| | — |
| | — |
| | — |
| | 20 |
| | 26 |
| (10 | ) | | 4 |
| | — |
| | — |
| | (9 | ) | | (15 | ) |
Cost recovery mechanisms – offset in electric revenue:(c) | | | | | | | | | | | | |
| Power supply costs | — |
| | 28 |
| | — |
| | — |
| | — |
| | 28 |
| |
| Transmission services recovery mechanism | — |
| | (6 | ) | | — |
| | — |
| | — |
| | (6 | ) | |
| Recovery of FAC under-recovery | 118 |
| | — |
| | — |
| | — |
| | — |
| | 118 |
| |
Cost recovery mechanisms – offset in electric revenue(c) | | 11 |
| | (18 | ) | | — |
| | — |
| | — |
| | (7 | ) |
| Total fuel and purchased power change | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | 26 |
| $ | 15 |
| | $ | (15 | ) | | $ | — |
| | $ | — |
| | $ | (9 | ) | | $ | (9 | ) |
| Net change in electric margins | $ | (84 | ) | | $ | 31 |
| | $ | — |
| | $ | 96 |
| | $ | (1 | ) | | $ | 42 |
| $ | 34 |
| | $ | 4 |
| | $ | — |
| | $ | 71 |
| | $ | (4 | ) | | $ | 105 |
|
| Natural gas revenue change: | | | | | | | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (7 | ) | | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 6 |
| $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
| Base rates (estimate) | — |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
| |
| QIP rider | | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Other | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
| — |
| | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
Cost recovery mechanism – offset in natural gas purchased for resale:(c) | | | | | | | | | | | | |
| Purchased natural gas costs | (2 | ) | | — |
| | (76 | ) | | — |
| | — |
| | (78 | ) | |
Other cost recovery mechanisms:(d) | | | | | | | | | | | | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) | |
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 | $ | (9 | ) | | $ | — |
| | $ | (29 | ) | | $ | — |
| | $ | — |
| | $ | (38 | ) | $ | (2 | ) | | $ | — |
| | $ | (11 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 6 |
| | $ | — |
| | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | (4 | ) | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Cost recovery mechanism – offset in natural gas revenue:(c) | | | | | | | | | | | | |
| Purchased natural gas costs | 2 |
| | — |
| | 76 |
| | — |
| | — |
| | 78 |
| |
Cost recovery mechanisms – offset in natural gas revenue(c) | | (2 | ) | | — |
| | 28 |
| | — |
| | — |
| | 26 |
|
| Total natural gas purchased for resale change | $ | 8 |
| | $ | — |
| | $ | 66 |
| | $ | — |
| | $ | — |
| | $ | 74 |
| $ | 2 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 30 |
|
| Net change in natural gas margins | $ | (1 | ) | | $ | — |
| | $ | 37 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| $ | — |
| | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2015 versus 2014 | 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) | $ | (20 | ) | | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (30 | ) |
| Base rates (estimate) | 82 |
| | 34 |
| | — |
| | 66 |
| | — |
| | 182 |
|
Sales volume (excluding the estimated effect of weather)
| (36 | ) | | (1 | ) | | — |
| | — |
| | — |
| | (37 | ) |
| Off-system sales, transmission services revenues, and capacity revenues | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| MEEIA 2013 net shared benefits | 33 |
| | — |
| | — |
| | — |
| | — |
| | 33 |
|
Transmission services revenues(e) | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Purchased power rider order in 2015 | — |
| | 15 |
| | — |
| | — |
| | — |
| | 15 |
|
| Other | 2 |
| | (10 | ) | | — |
| | 6 |
| | (16 | ) | | (18 | ) |
Cost recovery mechanisms – offset in fuel and purchased power:(c) | | | | | | | | |
|
| | |
| Power supply costs | — |
| | 81 |
| | — |
| | — |
| | — |
| | 81 |
|
| Transmission services recovery mechanism | — |
| | 10 |
| | — |
| | — |
| | — |
| | 10 |
|
| Recovery of FAC under-recovery | (5 | ) | | — |
| | — |
| | — |
| | — |
| | (5 | ) |
Other cost recovery mechanisms:(d) | | | | | | | | |
|
| | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | 10 |
| | — |
| | — |
| | — |
| | 10 |
|
| Gross receipts tax | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
| MEEIA 2013 program costs | 16 |
| | — |
| | — |
| | — |
| | — |
| | 16 |
|
| Total electric revenue change | $ | 82 |
| | $ | 129 |
| | $ | — |
| | $ | 72 |
| | $ | (16 | ) | | $ | 267 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
Effect of weather (estimate)(b) | 10 |
| | 10 |
| | — |
| | — |
| | — |
| | 20 |
|
| Effect of higher net energy costs included in base rates | (65 | ) | | — |
| | — |
| | — |
| | — |
| | (65 | ) |
FAC exclusion of transmission services charges(e) | (7 | ) | | — |
| | — |
| | — |
| | — |
| | (7 | ) |
| Other | (1 | ) | | 1 |
| | — |
| | — |
| | 12 |
| | 12 |
|
Cost recovery mechanisms – offset in electric revenue:(c) | | | | | | | | |
|
| | |
| Power supply costs | — |
| | (81 | ) | | — |
| | — |
| | — |
| | (81 | ) |
| Transmission services recovery mechanism | — |
| | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| Recovery of FAC under-recovery | 5 |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
| Total fuel and purchased power change | $ | (37 | ) | | $ | (80 | ) | | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | (105 | ) |
| Net change in electric margins | $ | 45 |
| | $ | 49 |
| | $ | — |
| | $ | 72 |
| | $ | (4 | ) | | $ | 162 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (17 | ) | | $ | — |
| | $ | (72 | ) | | $ | — |
| | $ | — |
| | $ | (89 | ) |
| Other | 2 |
| | — |
| | 1 |
| | — |
| | (2 | ) | | 1 |
|
Cost recovery mechanism – offset in natural gas purchased for resale:(c) | | | | | | | | |
|
| | |
| Purchased natural gas costs | (11 | ) | | — |
| | (113 | ) | | — |
| | — |
| | (124 | ) |
Other cost recovery mechanisms:(d) | | | | | | | | |
|
| | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Gross receipts tax | (1 | ) | | — |
| | (7 | ) | | — |
| | — |
| | (8 | ) |
| Total natural gas revenue change | $ | (27 | ) | | $ | — |
| | $ | (193 | ) | | $ | — |
| | $ | (2 | ) | | $ | (222 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 14 |
| | $ | — |
| | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | 76 |
|
Cost recovery mechanism – offset in natural gas revenue:(c) | | | | | | | | |
|
| | |
| Purchased natural gas costs | 11 |
| | — |
| | 113 |
| | — |
| | — |
| | 124 |
|
| Total natural gas purchased for resale change | $ | 25 |
| | $ | — |
| | $ | 175 |
| | $ | — |
| | $ | — |
| | $ | 200 |
|
| Net change in natural gas margins | $ | (2 | ) | | $ | — |
| | $ | (18 | ) | | $ | — |
| | $ | (2 | ) | | $ | (22 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 |
|
| |
| (a) | Includes an increase in transmission margins of $26 million and $43 million in 2017 and $35 million in 2016, and 2015, respectively, 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 $29 million, respectively, and the change in Other of -$6 million and $6 million, respectively. million. |
| |
| (b) | Represents the estimated variation resulting primarily from changes in cooling and heating degree-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 energy adjustment, zero-emission credits, transmission services, and purchased natural gas cost recovery mechanisms, as well as FAC recoveries. Electric and natural gas revenue changes are offset by corresponding changes in Fuel, Purchasedfuel, purchased power, and Naturalnatural gas purchased for resale, resulting in no change to electric and natural gas margins. |
| |
| (d) | Includes amounts for bad debt, energy-efficiency programs, and environmental remediation cost recovery mechanisms, as well as gross receipts tax revenues. See Other Operations and Maintenance Expenses or Taxes Other Than Income Taxes in this section for the related offsetting increase or decrease to expense. These items have no overall impact on earnings. |
| |
(e) | Ameren Missouri amounts are subsequent to May 30, 2015, due to the exclusion of transmission revenues and substantially all transmission charges from the FAC as a result of the April 2015 MoPSC electric rate order. |
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 million, or 2%, in 2017 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, 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 base 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. 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 affected 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'sAmeren’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. Ameren'sAmeren’s natural gas margins increased $36 million, or 7%, in 2016 compared with 2015, primarily because of increased margins at Ameren Illinois Natural Gas.
Ameren MissouriTransmission
Ameren Missouri hasTransmission’s margins increased $96 million, or 37%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a FAC cost recovery mechanism that allows it42% increase in rate base used to recover or refund, through customer rates, 95%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 changes12.38% for nearly four months in net energy costs greater or less than 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.
Net energy costs, as defined in the FAC, include fuel and purchased power costs, including transportation, net of off-system sales. Since May 2015, when transmission revenues and substantially all transmission charges were excluded from net energy costs2016 as a result of the Aprilexpiration of the refund period in the February 2015 MoPSC electric rate order, electric margins have been unfavorably affected, as discussed below. 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.FERC complaint case.
Ameren Missouri'sMissouri
Ameren Missouri’s electric margins decreased $84 million, or 3%, in 2016 compared with 2015. Ameren Missouri’s natural gas margins were comparable between years.
The following items had an unfavorable effect on Ameren Missouri'sMissouri’s electric margins:
margins in 2016 compared with 2015:
The suspension of the New Madrid Smelter operations in the first quarter of 2016, which decreased margins by $57 million. The change in margins due to lower sales to the New Madrid Smelter is the sum of New Madrid Smelter revenues (-$129 million) and New Madrid Smelter energy costs (+$72 million) in the Electric and Natural Gas Margins table above. New Madrid Smelter energy costs includeincluded the impact of a provision in the FAC tariff that, under certain circumstances, allowsallowed Ameren Missouri to retain a portion of the revenues from any off-system sales it makesmade as a result of reduced sales to the New Madrid Smelter. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the New Madrid Smelter.
The expiration of MEEIA 2013, which decreased margins by $57 million. The change in margins due to the expiration of MEEIA 2013 is the sum of MEEIA 2013 net shared benefits (-$85 million) and MEEIA 2013 performance incentive (+$28 million) in the Electric and Natural Gas Margins table above. Net shared benefits compensated Ameren Missouri 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.
Increased transmission services charges resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, and shared by all MISO participants, which decreased margins by $16 million.
The following items had a favorable effect on Ameren Missouri'sMissouri’s electric margins in 2016 compared with 2015:
Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 16%, while heating degree-days decreased 6%. The net effect of weather 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, 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 net energy costs included in base rates (-$34 million) 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 sum of the change 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.
Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effect of weather, total retail sales volumes increased by less than 1%, which increased revenues by $7 million, due to an additional day as a result of the leap year and growth, partially offset by the carryover effect of MEEIA 2013 on sales volumes and the effect of MEEIA 2016 customer energy efficiencyenergy-efficiency programs. MEEIA 2016 customer energy efficiencyenergy-efficiency programs reduced retail sales volumes but the throughput disincentive recovery ensured that electric margins were not affected.
Ameren Missouri's natural gas margins were comparable between years. Ameren Missouri has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased natural 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 Illinois
Ameren Illinois'Illinois’ electric margins increased by $74 million, or 6%, in 2016 compared with 2015, driven by increases in Ameren Illinois Electric Distribution ($31 million) and Ameren Illinois Transmission ($43 million) margins. Ameren Illinois Natural Gas’ margins increased $37 million, or 9%, in 2016 compared with 2015.
Ameren Illinois Electric Distribution
The IEIMA performance-based formula rate framework
provides an annual reconciliation of the electric delivery service revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If the current year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) in the Electric and Natural Gas Margins table above. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois Electric Distribution's revenue requirement reconciliation pursuant to the IEIMA.
Ameren Illinois Electric Distribution has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its customers. These pass-through costs do not affect Ameren Illinois Electric Distribution's margins, as any change in costs is offset by a corresponding change in revenues.
Ameren Illinois Electric Distribution'sDistribution’s margins increased $31 million, or 3%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Electric Distribution'sDistribution’s electric margins:
Revenues increased by $38 million, primarily due tobecause of an increase in rate base of 8% and higher recoverable costs in 2016 compared with 2015, under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity due to a reduction in 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%. The net effect of weather increased margins by an estimated $7 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'sDistribution’s margins were unfavorably affected by the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois'Illinois’ cumulative power usage cost and its purchased power rider mechanism, which increased margins by $15 million in 2015.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased natural gas costs do not affect Ameren Illinois
Natural Gas' margins, as any change in costs is offset by a corresponding change in revenues.
Ameren Illinois Natural Gas'Gas’ margins increased $37 million, or 9%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Natural Gas'Gas’ margins:
Higher natural gas base rates in 2016, which increased margins by an estimated $42 million.
The absence of warmer-than-normal 2015 winter temperatures and the application of the VBA in 2016, which increased margins by $3 million. The VBA, which was approved by the ICC in December 2015, eliminated the impact of weather on natural gas margins 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.
Ameren Illinois Transmission
Ameren Illinois Transmission'sTransmission’s margins increased $43 million, or 23%, in 2016 compared with 2015,2015. Margins were favorably affected by increased capital investment, as discussedevidenced by a 27% increase in the Ameren Transmission section below.
Ameren Transmission
The provisions of FERC's electric transmission formula rate framework provide for an annual reconciliation of the electric transmission service revenue requirement necessarybase used to reflect the actual costs incurred in a given year withcalculate the revenue requirement, in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If the current year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) in the Electric and Natural Gas Margins table above. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Transmission's revenue requirement reconciliation.
Ameren Transmission's margins increased $96 million, or 37%, in 2016 compared with 2015, driven by Ameren Illinois Transmission and ATXI results. The increase in margins for both Ameren Transmission and Ameren Illinois Transmission was primarily due to significant capital investment, which increased rate base by 42% and 27%, respectively, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. See Cash Flows from Investing Activities in this section for information regarding capital expenditures, including those for the Illinois Rivers project. Ameren Transmission and Ameren Illinois
Transmission marginsMargins 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. 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.
2015 versus 2014
Ameren
Ameren's electric margins increased $162 million, or 4%, in 2015 compared with 2014, primarily because of increased margins at Ameren Transmission, Ameren Illinois Electric Distribution, and Ameren Missouri. Ameren's natural gas margins decreased $22 million, or 4%, in 2015 compared with 2014, primarily because of decreased margins at Ameren Illinois Natural Gas.
Ameren Missouri
Ameren Missouri's electric margins increased $45 million, or 2%, in 2015 compared with 2014. The following items had a favorable effect on Ameren Missouri's electric margins:
Higher MEEIA 2013 net shared benefits caused by increased customer implementation of longer-lived energy efficiency products and increased nonresidential customer participation, which increased revenues by $33 million. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency-related volume reductions in current and future periods.
Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $17 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$82 million) and the change in effect of higher net energy costs included in base rates (-$65 million) in the Electric and Natural Gas Margins table above.
The following items had an unfavorable effect on Ameren Missouri's electric margins in 2015 compared with 2014:
Lower sales volumes, primarily caused by the MEEIA 2013 programs and other customer energy efficiency measures, and reduced sales to the New Madrid Smelter. Excluding the estimated effect of weather and reduced sales to the New Madrid Smelter, total retail sales volumes decreased by 1%, which decreased revenues by $25 million. Reduced sales to the New Madrid Smelter decreased revenues by $11 million. The sales volumes to the New Madrid Smelter were lower than those reflected in rates established in the April 2015 MoPSC electric rate order. Lower sales volumes led to a decrease in net energy costs of $24 million. The change in net energy costs is the sum of the change in off-system sales, transmission services revenues, and capacity revenues (+$3 million) and the change in energy costs (excluding the estimated effect of weather) (+$21 million) in the Electric and Natural Gas Margins table above.
Winter temperatures in 2015 were warmer compared with 2014, as heating degree-days decreased 19%. The effect of weather decreased margins by an estimated $10 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$20 million) and the effect of weather (estimate) on fuel and purchased power (+$10 million) in the Electric and Natural Gas Margins table above.
The exclusion of transmission revenues and substantially all transmission charges from the FAC beginning May 30, 2015, which decreased margins by $6 million. The change in margins as a result of the changes to the FAC is the sum of FAC exclusion of transmission services charges (-$7 million) and transmission services revenues (+$1 million) in the Electric and Natural Gas Margins table above.
Ameren Missouri's natural gas margins were comparable between years.
Ameren Illinois
Ameren Illinois' electric margins increased by $84 million, or 7%, in 2015 compared with 2014 driven by increases in Ameren Illinois Electric Distribution ($49 million) and Ameren Illinois Transmission ($35 million) margins.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution's revenues increased $129 million in 2015 compared with 2014, primarily because of higher power supply costs as a result of increased MISO capacity prices. Ameren Illinois Electric Distribution has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its electric distribution customers. These pass-through costs do not affect Ameren Illinois Electric Distribution's margins, as any change in costs is offset by a corresponding change in revenues.
Ameren Illinois Electric Distribution's margins increased $49 million, or 5%, in 2015 compared with 2014. The following items had a favorable effect on Ameren Illinois Electric Distribution's electric margins:
Revenues increased by $34 million, primarily due to an increase in rate base of 8% and higher recoverable costs in 2015 compared with 2014 under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity due to a reduction in 30-year United States Treasury bond yields, which decreased 50 basis points in 2015 compared with 2014.
A January 2015 ICC order regarding Ameren Illinois' cumulative power usage cost and its purchased power rider mechanism, which caused electric revenues to increase by $15 million compared with 2014.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas' revenues decreased $193 million in 2015 compared with 2014 because of lower natural gas commodity prices and lower sales volumes due to weather. Ameren Illinois Natural Gas has a cost recovery mechanism for natural gas
purchased on behalf of its customers. These pass-through purchased natural gas costs do not affect Ameren Illinois Natural Gas' margins, as any change in costs is offset by a corresponding change in revenues.
Ameren Illinois Natural Gas' margins decreased $18 million, or 4%, in 2015 compared with 2014. Winter temperatures in 2015 were warmer compared with 2014, as heating degree-days decreased 18%, which decreased margins by an estimated $10 million. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (-$72 million) and the effect of weather (estimate) on natural gas purchased for resale (+$62 million) in the Electric and Natural Gas Margins table above.
Ameren Illinois Transmission
Ameren Illinois Transmission's margins increased $35 million, or 23%, in 2015 compared with 2014, as discussed in the Ameren Transmission section below.
Ameren Transmission
Ameren Transmission's margins increased $72 million, or 39%, in 2015 compared with 2014, driven by Ameren Illinois Transmission and ATXI results. The increase in margins for both Ameren Transmission and Ameren Illinois Transmission was primarily due to significant capital investment, which increased rate base by 54% and 27%, respectively, as well as higher recoverable costs in 2015 compared with 2014 under forward-looking formula ratemaking. See Cash Flows from Investing Activities in this section for information regarding capital expenditures, including those for the Illinois Rivers project. Ameren Transmission and Ameren Illinois Transmission margins were reduced by an estimate of the probable customer refunds as a result of the FERC complaint cases regarding the allowed base return on common equity. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the FERC complaint cases.case.
Other Operations and Maintenance Expenses
2017 versus 2016
Ameren
Other operations and maintenance expenses decreased $16 million in 2017 compared with 2016, because of items discussed below and an increase in intersegment eliminations of $14 million.
Ameren Transmission
Other operations and maintenance expenses increased $3 million in 2017 compared with 2016, primarily because of an increase in labor costs due to increased wages and staffing additions.
Ameren Missouri
Other operations and maintenance expenses were $9 million higher in 2017 compared with 2016. The following items increased other operations and maintenance expenses between years:
MEEIA customer energy-efficiency program costs increased by $22 million.
Labor and benefit costs increased by $11 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, excluding refueling and maintenance outage costs at the Callaway energy center, increased by $3 million, primarily due to higher coal handling charges.
The following items decreased other operations and maintenance expenses between years:
Employee benefit costs decreased by $21 million, primarily due to a reduction in the base level 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.
Ameren Illinois
Other operations and maintenance expenses decreased $15 million in 2017 compared with 2016, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission in 2017 compared with 2016.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $26 million lower in 2017 compared with 2016, primarily because of a $47 million decrease in customer energy-efficiency costs, which was partially offset by an $11 million increase in environmental remediation costs and a $3 million increase in labor costs resulting from increased wages.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $9 million higher 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 decreased expenses at Ameren Missouri and Ameren Illinois Natural Gas, partially offset by an increase in expenses at Ameren Illinois Electric Distribution, Ameren Transmission,system operations and other businesses.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 efficiencyenergy-efficiency program costs decreased by $34 million in 2016, primarily due tobecause of the expiration of MEEIA 2013, partially offset by costs incurred
for MEEIA 2016. Electric revenues decreased by a corresponding amount, with no overall effect on net income.
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 related to reduced system repair and vegetation management work.
Employee benefit costs decreased by $11$15 million, primarily due tobecause of a $6 million reduction 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. Electric base rates billed to customers related to pension and postretirement expenses decreased electric revenues bycosts, as well as a corresponding amount, with no overall effect on net income.
An unrealized MTM gain in 2016 compared with an unrealized MTM loss in 2015 decreased costs by $4 million resulting fromdecrease due to changes in the market 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 due tobecause 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.
Amortization of previously deferred solarSolar rebate costs increased by $9 million, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers increased electric revenues by a corresponding amount, with no overall effect on net income.
Storm-related repair costs increased by $7 million.
Ameren Illinois
Other operations and maintenance expenses increased $7 million in 2016 compared with 2015, primarily because of increased expenses at Ameren Illinois Electric Distribution and Ameren Illinois Transmission, partially offset by a reduction in expenses at Ameren Illinois Natural Gas.as discussed below.
Ameren Illinois Electric Distribution
Pursuant to the provisions of the IEIMA's formula rate framework, recoverable electric distribution costs that are not recovered through separate cost recovery mechanisms are included in a revenue requirement reconciliation, which results in a corresponding adjustment to electric revenues, with no overall effect on net income. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.
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 staffstaffing 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. These expenses are included in cost riders that result in increased electric revenues, with no overall effect on net income.
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, primarily due to lower pension 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, 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,energy-efficiency, and environmental remediation costs decreased by $10 million. These expenses are included in cost riders that result in lower natural gas revenues, with no overall effect on net income.
Employee benefit costs decreased by $5 million, primarily due tobecause 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 related to increased pipeline integrity and storage field maintenance.
Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.
Ameren Illinois Transmission
Other operations and maintenance expenses were $5 million higher in 2016 compared with 2015, primarily because of an increase in system operations and labor costs.
Ameren Transmission
Pursuant to the provisions of the FERC's formula rate framework, recoverable transmission costs that are not recovered through separate cost recovery mechanisms are included in Ameren Transmission's and Ameren Illinois Transmission's revenue requirement reconciliations, which result in corresponding adjustments to electric revenues, with no overall effect on net income. These recoverable transmission costs are included in other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.
Other operations and maintenance expenses increased $4 million in 2016 compared with 2015, primarily because of an increase in system operations and labor costs.
2015 versus 2014
Ameren
Other operations and maintenance expenses increased $10 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Illinois Electric Distribution and Ameren Transmission, partially offset by a reduction in expenses at Ameren Missouri. Other operations and maintenance expenses were comparable between years at Ameren Illinois Natural Gas.
Ameren Missouri
Other operations and maintenance expenses were $14 million lower in 2015 compared with 2014. The following items decreased other operations and maintenance expenses between years:
Refueling and maintenance outage costs at the Callaway energy center decreased by $27 million. There was no refueling outage scheduled in 2015; however, $9 million in preparation costs were incurred in 2015 for the 2016 scheduled outage.
Employee benefit costs decreased by $9 million, primarily due to a change in pension and postretirement expenses allowed in rates as a result of the April 2015 MoPSC electric rate order.
Disposal costs for low-level radioactive nuclear waste decreased by $8 million.
Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, decreased by $6 million, primarily because of fewer major outages.
Bad debt expense decreased by $3 million, due to improved customer collections.
The following items increased other operations and maintenance expenses between years:
Amortization of previously-deferred solar rebate costs increased by $17 million as a result of the April 2015 MoPSC electric rate order.
MEEIA customer energy efficiency program costs increased by $16 million in 2015, primarily due to program enhancements and increased customer participation.
An unrealized MTM loss in 2015 compared with an unrealized MTM gain in 2014 increased costs by $3 million, resulting from changes in the market value of company-owned life insurance.
Electric distribution maintenance expenditures increased by $2 million, primarily related to increased system repair work.
Ameren Illinois
Other operations and maintenance expenses increased $26 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Illinois Electric Distribution. Other operations and maintenance expenses were comparable between years at Ameren Illinois Natural Gas and Ameren Illinois Transmission.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $25 million higher in 2015 compared with 2014. The following items increased other operations and maintenance expenses between years:
Bad debt, customer energy efficiency, and environmental remediation costs increased by $10 million.
Circuit maintenance and system repair work increased by $7 million, primarily related to regulatory compliance requirements.
Labor costs increased by $5 million, primarily because of staff additions to meet enhanced standards and goals related to the IEIMA and higher wages.
Storm-related repair costs increased by $3 million.
Employee benefit costs increased by $3 million, primarily due to higher pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
Ameren Transmission
Other operations and maintenance expenses increased $7 million in 2015 compared with 2014, primarily because of increased expenses at ATXI, resulting from an increase in support services, labor costs and consulting expenditures.
Provision for Callaway Construction and Operating License
PrimarilyAmeren 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, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site in 2015.Missouri. As a result of this decision, in 2015, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision in 2015 for the previously capitalized COL costs.
Depreciation and Amortization
2017 versus 2016
Depreciation and amortization expenses increased $51 million, $19 million, and $22 million in 2017 compared with 2016 at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment across their respective segments.
2016 versus 2015
Ameren
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 of increased expenses atadditional property, plant, and equipment across their respective segments. Additionally, Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, as discussed below.
Ameren Missouri
Depreciation and amortization expenses increased $22 million, primarily because of electric system capital additions and increasedMissouri’s depreciation rates resulting fromincreased as a result of the April 2015 MoPSC electric rate order.
Ameren Illinois
Depreciation and amortization expenses increased $24 million, primarily because of increased expenses at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, as discussed below.
Ameren Illinois Electric Distribution
Depreciation and amortization expenses increased $14 million, primarily because of capital additions.
Ameren Illinois Natural Gas
Depreciation and amortization expenses increased $3 million, primarily because of capital additions.
Ameren Illinois Transmission
Depreciation and amortization expenses increased $7 million, primarily because of capital additions.
Ameren Transmission
Depreciation and amortization expenses increased $10 million, primarily because of capital additions at Ameren Illinois Transmission.
2015 versus 2014
Ameren
Depreciation and amortization expenses increased $51 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, as discussed below.
Ameren Missouri
Depreciation and amortization expenses increased $19 million, primarily because of multiple significant electric projects completed in 2014 and increased depreciation rates resulting from the April 2015 MoPSC electric rate order.
Ameren Illinois
Depreciation and amortization expenses increased $32 million, primarily because of increased expenses at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, as discussed below.
Ameren Illinois Electric Distribution
Depreciation and amortization expenses increased $15 million, primarily because of capital additions.
Ameren Illinois Natural Gas
Depreciation and amortization expenses increased $11 million, primarily because of capital additions.
Ameren Illinois Transmission
Depreciation and amortization expenses increased $6 million, primarily because of capital additions.
Ameren Transmission
Depreciation and amortization expenses increased $7 million, primarily because of capital additions at Ameren Illinois Transmission.
Taxes Other Than Income Taxes
20162017 versus 20152016
Ameren
Taxes other than income taxes decreased $6increased $10 million in 20162017 compared with 2015, primarily because of decreased expenses at Ameren Missouri, partially offset by increased expenses at Ameren Illinois Natural Gas and Ameren Transmission,2016, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution.Transmission. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
Ameren Missouri
Taxes other than income taxes increased $3 million, primarily because of higher gross receipts taxes resulting from an increase in electric revenues.
Ameren Illinois
Taxes other than income taxes increased $5 million, primarily because of increased property taxes at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas. Taxes other than income taxes were comparable at Ameren Illinois Transmission.
2016 versus 2015
Ameren
Taxes other than income taxes decreased $6 million 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 a decrease indecreased property taxes. Electric revenues for gross receipts taxes decreased by an amount corresponding to the reduction in gross receipts taxes, with no overall effect on net income.
Ameren Illinois
Taxes other than income taxes increased $2 million, primarily because of increased expenses at Ameren Illinois Natural Gas, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Transmission.
Ameren Illinois Natural Gas
Taxes other than income taxes increased $2 million, primarily because of an increase in Illinois state natural gas invested capital taxes.
Ameren Transmission
Taxes other than income taxes increased $2 million, primarily because of an increase in property taxes at ATXI.
2015 versus 2014
Ameren
Taxes other than income taxes increased $5 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Missouri, partially offset by decreased expenses at Ameren Illinois Natural Gas, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution and Ameren Transmission.
Ameren Missouri
Taxes other than income taxes increased $13 million, primarily because of increased property taxes resulting from both higher tax rates and assessed property tax values, and increased gross receipts taxes resulting from higher electric service rates.
Ameren Illinois
Taxes other than income taxes decreased $8 million, primarily because of decreased expenses at Ameren Illinois Natural Gas, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Transmission.
Ameren Illinois Natural Gas
Taxes other than income taxes decreased $7 million, primarily because of decreased gross receipts taxes resulting from lower natural gas sales prices and volumes.
Other Income and Expenses
20162017 versus 20152016
Ameren
Other income, net of expenses, was comparable between yearsdecreased $4 million in 2017 compared with 2016, primarily due to decreased income at Ameren, Ameren Missouri, Ameren Illinois Electric Distribution, as discussed below, along with a decrease in the allowance for equity funds used during construction, partially offset by decreased donations in 2017. Other income, net of expenses, was comparable at the remaining Ameren Illinois Natural Gas, and Ameren Transmission.segments. See Note 6 – Other Income and Expenses under Part II, Item 8, of this report for additional information.
Ameren Illinois
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, Illinois,Ameren Missouri, Ameren Illinois, Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.their respective segments.
2015Interest Charges
2017 versus 20142016
Ameren
Other income, net of expenses, decreased $13Interest charges increased $9 million in 20152017 compared with 2014,2016, as discussed below.
Ameren Transmission
Interest charges increased $9 million, primarily because of a $5 million increase in donations at Ameren (parent) due to the timing of charitable contributions and a decrease in other income, net of expenses, at Ameren Missouri and Ameren Transmission, partially offset by an increase in other income, net of expenses,average outstanding debt at Ameren Illinois Electric Distribution, as discussed below. Other income, net of expenses, was comparable between years at Ameren Illinois Natural Gas.and ATXI.
Ameren Missouri
Other income, net of expenses,Interest charges decreased $7$4 million, primarily because of a decrease in the allowance for equity funds used during construction, as multiple significant electric capital projects were completed in 2014.average interest rate of debt.
Ameren Illinois
Other income, net of expenses, was comparable between years. Other income, net of expenses, was lower at Ameren Illinois Transmission, partially offset by an increase in other income, net of expenses, at Ameren Illinois Electric Distribution, as discussed below. Other income, net of expenses, was comparable between years at Ameren Illinois Natural Gas.
Ameren Illinois Electric Distribution
Other income, net of expenses,Interest charges increased $4 million, primarily because of increasedan increase in average outstanding debt, partially offset by a decrease in the average interest income onrate of debt. Interest charges were comparable between years at each of the IEIMA 2013, 2014, and 2015 revenue requirement reconciliation regulatory assets.
Ameren Illinois Transmission
Other income, net of expenses, decreased $4 million, primarily because of decreased income from customer-requested construction.
Ameren Transmission
Other income, net of expenses, decreased $4 million, primarily because of decreased income from customer-requested construction at Ameren Illinois Transmission.
Interest Chargessegments.
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 costaverage 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 chargesrate of debt at Ameren Transmission was partially offset by a decrease in the average interest chargesrate of debt at Ameren Missouri, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.
Ameren Transmission
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 because of an increase in interest charges at Ameren Illinois Transmission.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'Illinois’ average outstanding debt interest charges on regulatory liabilities, 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.
Ameren Transmission
Interest charges increased $23 million, primarily because of an increase in ATXI's and Ameren Illinois' average outstanding debt and an increase in the cost of debt.
2015 versus 2014
Ameren
Interest charges increased $14 million in 2015 compared with 2014, primarily because of increases in interest charges at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, as discussed below. The increases were offset, in part, by a reduction in interest charges at Ameren (parent) of $15 million, primarily because of a decrease in average outstanding debt. Ameren (parent) repaid senior unsecured notes in May 2014, with proceeds from commercial paper issuances. Ameren (parent) issued senior unsecured notes in November 2015, the proceeds of which were used to repay commercial paper borrowings.
Ameren Missouri
Interest charges increased $8 million, primarily because of a decrease in the allowance for funds used during construction, as multiple significant electric projects were completed in 2014, and because of an increase in average outstanding debt.
Ameren Illinois
Interest charges increased $19 million, primarily because of an increase in average outstanding debt.
Ameren Illinois Electric Distribution
Interest charges increased $8 million, because of an increase in Ameren Illinois' average outstanding debt, and the absence in 2015 of a reduction from an ICC rate order received in December 2014, which partially reversed a charge recorded in 2013 that had disallowed the recovery from customers of certain debt premium costs.
Ameren Illinois Natural Gas
Interest charges increased $7 million, because of an increase in Ameren Illinois' average outstanding debt, and the absence in 2015 of a reduction from an ICC rate order received in December 2014, which partially reversed a charge recorded in 2013 that had disallowed the recovery from customers of certain debt premium costs.
Ameren Illinois Transmission
Interest charges increased $4 million, primarily because of an increase in Ameren Illinois' average outstanding debt.
Ameren Transmission
Interest charges increased $9 million, because of increased borrowings at ATXI and an increase in average outstanding debt at Ameren Illinois Transmission.
Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2017, 2016, 2015, and 2014:
| | | | 2016 | 2015 | 2014 | | 2017 | | 2016 | | 2015 | |
| Ameren | 37% | 38% | 39% | Ameren | 52% | (a) | 37% | | 38% | |
| Ameren Missouri | 38% | 37% | Ameren Missouri | 44% | (b) | 38% | | 37% | |
| Ameren Illinois | 38% | 37% | 41% | Ameren Illinois | 38% | (c) | 38% | | 37% | |
| Ameren Illinois Electric Distribution | 38% | 36% | 40% | Ameren Illinois Electric Distribution | 38% | (c) | 38% | | 36% | |
| Ameren Illinois Natural Gas | 39% | 40% | 43% | Ameren Illinois Natural Gas | 38% | (c) | 39% | | 40% | |
| Ameren Illinois Transmission | 38% | 37% | 42% | Ameren Illinois Transmission | 37% | (c) | 38% | | 37% | |
| Ameren Transmission | 39% | 38% | 42% | 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. |
See Note 1312 – 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.
Illinois, as well as a discussion of the effect of the TCJA and the revaluation of deferred taxes in 2017.2017 versus 2016
Ameren
The effective income tax rate was higher in 2017 compared with 2016, primarily because of revaluation of deferred taxes due to enactment of the TCJA, which decreased the federal statutory corporate income tax rate from 35% to 21% for years after 2017. In addition, income tax expense increased due to the revaluation 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 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. 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.
Ameren Transmission
The effective income tax rate was comparable between years.
Ameren Missouri
The effective income tax rate was higher, primarily because of revaluation of deferred taxes due to the reduction in the federal statutory corporate income tax rate described above.
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 one percentage point reduction in the 2016 effective tax rate, as compared towith 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 towith 2015 at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between years at the remaining Ameren Missouri, Ameren Illinois Natural Gas, and Ameren Transmission.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 Natural Gas and Ameren Illinois Transmission.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.
2015 versus 2014
Ameren
The effective tax rate was comparable between years. The effective tax rate was lower in 2015 as compared to 2014 at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, primarily because of items detailed below. The effective tax rate was comparable between years at Ameren Missouri.
Ameren Illinois
The effective tax rate was lower, primarily because of items discussed at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission below. The Illinois statutory income tax rate was 9.5% in 2014 and decreased to 7.75% in 2015.
Ameren Illinois Electric Distribution
The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015, as well as higher tax benefits from certain depreciation differences on property-related items and fewer non-tax deductible costs.
Ameren Illinois Natural Gas
The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015 and the 2014 impacts on accumulated deferred income taxes of reducing the state statutory rate.
Ameren Illinois Transmission
The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015, as well as higher tax benefits from certain depreciation differences on property-related items and higher non-taxable income.
Ameren Transmission
The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015, as well as higher tax benefits from certain depreciation differences on property-related items and higher non-taxable income at Ameren Illinois Transmission.
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. No material activity was recorded associated with discontinued operations in 2014. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
LIQUIDITY AND CAPITAL RESOURCES
OurCollections from our tariff-based gross margins 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, borrowings under the Credit Agreements, commercial paper issuances, money pool borrowings, or, in the case of Ameren Missouri and Ameren Illinois, other short-term affiliate borrowings from affiliates 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 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 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. 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. 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, environmental compliance, and other improvements. We intendAs part of its plan to fund thosethese capital expenditures, primarilybeginning 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 and expects to do so over the next five years. Additionally, we may be required to issue incremental debt and/or equity, with cash provided by operating activitiesthe long-term intent to maintain strong financial metrics and short-term and long-term debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.as calculated in accordance with ratemaking frameworks.
The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments maywill periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2016,2017, for the Ameren Companies. The working capital deficit as of December 31, 2016,2017, 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, the Ameren Companies had access to $1.5$1.6 billion of liquidity at December 31, 2016.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 20162017, 20152016, and 20142015:
| | | | Net Cash Provided by (Used in) Operating Activities | | Net Cash Provided by (Used in) Investing Activities | | Net Cash Provided by (Used in) Financing Activities | Net Cash Provided by (Used in) Operating Activities | | Net Cash Used in Investing Activities | | Net Cash Provided by (Used in) Financing Activities |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Ameren(a) – continuing operations | $ | 2,124 |
| | $ | 2,035 |
| | $ | 1,571 |
| | $ | (2,141 | ) | | $ | (1,951 | ) | | $ | (1,856 | ) | | $ | (265 | ) | | $ | 232 |
| | $ | 127 |
| $ | 2,104 |
| | $ | 2,124 |
| | $ | 2,035 |
| | $ | (2,205 | ) | | $ | (2,141 | ) | | $ | (1,951 | ) | | $ | 102 |
| | $ | (265 | ) | | $ | 232 |
|
Ameren(a) – discontinued operations | (1 | ) | | (4 | ) | | (6 | ) | | — |
| | (25 | ) | | 139 |
| | — |
| | — |
| | — |
| — |
| | (1 | ) | | (4 | ) | | — |
| | — |
| | (25 | ) | | — |
| | — |
| | — |
|
| Ameren Missouri | 1,169 |
| | 1,247 |
| | 950 |
| | (934 | ) | | (724 | ) | | (837 | ) | | (434 | ) | | (325 | ) | | (113 | ) | 1,016 |
| | 1,169 |
| | 1,247 |
| | (685 | ) | | (934 | ) | | (724 | ) | | (331 | ) | | (434 | ) | | (325 | ) |
| Ameren Illinois | 803 |
| | 763 |
| | 445 |
| | (918 | ) | | (913 | ) | | (828 | ) | | 44 |
| | 220 |
| | 383 |
| 815 |
| | 803 |
| | 763 |
| | (1,070 | ) | | (918 | ) | | (913 | ) | | 255 |
| | 44 |
| | 220 |
|
| |
| (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 adjustment mechanisms, which may be adjusted without a traditional rate proceeding. Similar regulatory mechanisms exist for certain operating expenses that can also affect the timing of cash provided by operating activities. EachThe timing of these types ofcash payments for costs recoverable under our regulatory mechanisms have differentdiffers from the recovery periods from when we pay a cost that is included in a regulatory mechanism until we receive cash from customers.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 impactaffect 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-adjustment mechanisms.
2017 versus 2016
Ameren
Ameren’s cash from operating activities associated with continuing operations decreased $20 million in 2017, compared with 2016. The following items contributed to the decrease:
A $48 million decrease in 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.
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 $4 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 cash from operating activities associated with continuing operations between years:
A $167 million increase 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 $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 collected from Ameren Illinois’ alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.
A $14 million decrease in coal inventory because of decreased market prices and decreased purchases at Ameren Missouri as a result of inventory reductions at its energy centers.
Ameren’s cash from operating activities associated with discontinued operations was immaterial in both 2017 and 2016.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased $153 million in 2017, compared with 2016. The following items contributed to the decrease:
An increase in income tax payments of $151 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to higher taxable income 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.
A $27 million decrease in net energy costs collected from customers under the FAC.
A $20 million decrease in cash related to customer energy-efficiency program recovery mechanisms.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities between years:
A $70 million increase 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 $14 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.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased $12 million in 2017, compared with 2016. The following items contributed to the increase:
A $75 million increase 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 $37 million increase 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, 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:
A $126 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.
A $70 million decrease in pension and postretirement benefit plan contributions.
A $42 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'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 decreaseincrease in payments for purchasedcash related to Ameren Illinois’ power compared with amounts collected from Ameren Illinois customers through a riderprocurement 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 experienced in 2014.
A $33 million decreaseincrease in expenditures forcash related to customer energy efficiencyenergy-efficiency program costs compared with amounts collected from customers.recovery mechanisms.
A $19 million increase in cash associated with the recovery of Ameren Illinois'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'sAmeren’s cash from operating activities associated with continuing operations between years: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'sMissouri’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 between years: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 experienced in 2014.
A $33 million decrease in pension and postretirement benefit plan contributions.
AAn $11 million decreaseincrease in expenditures forcash related to customer energy efficiencyenergy-efficiency program costs compared with amounts collected from customers.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 decreaseincrease in payments for purchasedcash related to the power compared with amounts collected from customers through a riderprocurement cost recovery mechanism.
A $22 million decrease in pension and postretirement benefit plan contributions.
A $22 million decreaseincrease in expenditures forcash related to customer energy efficiencyenergy-efficiency program costs compared with amounts collected from customers.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 between periods:during 2016, compared with 2015:
IncomeA $121 million decrease resulting from income tax payments of $8 million in 2016, compared with income tax refunds of $113 million in 2015.2015, 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, maintenance, and IEIMA projects.
A $7 million increase in interest payments, primarily due to an increase in the average outstanding debt, including senior secured notes issued in December 2015.
2015 versus 2014
Ameren
Ameren’s cash from operating activities associated with continuing operations increased $464 million in 2015, compared with 2014. The following items contributed to the increase:
A $192 million increase 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 $149 million increase in net energy costs collected from Ameren Missouri customers under the FAC.
A $137 million increase in cash associated with the recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments, as Ameren Illinois collected $69 million from customers in 2015 and refunded $68 million to customers in 2014.
A $57 million decrease in Ameren Missouri rebate payments provided for customer-installed solar generation, as the rebate program was substantially completed by the end of 2014.
A $33 million increase in natural gas commodity costs collected from customers under the PGAs, primarily related to Ameren Illinois.
A $31 million decrease in the cost of natural gas held in storage caused primarily by lower natural gas prices.
A $19 million decrease in payments for nuclear refueling and maintenance outages at the Ameren Missouri Callaway energy center. There was no refueling and maintenance outage in 2015; however, there were cash expenditures related to the planned 2016 spring outage made in 2015.
The following items partially offset the increase in Ameren's cash from operating activities associated with continuing operations during 2015, compared with 2014:
A $49 million increase in coal inventory costs at Ameren Missouri caused by increased volumes resulting from the absence of weather-related railroad delivery delays that occurred in 2014.
A net $29 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.
A $24 million decrease in income tax refunds primarily due to the absence in 2015 of tax settlements pertaining to 2007 through 2011 that were received in 2014. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for income tax refund information.
A $24 million increase in pension and postretirement benefit plan contributions.
A $7 million increase in property tax payments at Ameren Missouri caused by both higher assessed property tax values and tax rates.
A $7 million increase in expenditures for customer energy efficiency programs compared with amounts collected from Ameren Illinois customers.
Ameren’s cash from operating activities associated with discontinued operations was comparable between 2015 and 2014.
Ameren Missouri
Ameren Missouri’s cash from operating activities increased $297 million in 2015, compared with 2014. The following items contributed to the increase:
A $149 million increase in net energy costs collected from customers under the FAC.
A $143 million decrease in income taxes paid to Ameren (parent) pursuant to the tax allocation agreement, primarily related to a change in the tax treatment for generation repairs adopted in 2013, which increased payments in 2014.
A $57 million decrease in rebate payments provided for customer-installed solar generation, as the rebate program was substantially completed by the end of 2014.
A $37 million increase 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 $19 million decrease in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center. There was no refueling and maintenance outage in 2015; however, there were cash expenditures related to the 2016 spring outage made in 2015.
The following items partially offset the increase in Ameren Missouri's cash from operating activities during 2015, compared with 2014:
A $49 million increase in coal inventory costs caused by increased volumes resulting from the absence of weather-related railroad delivery delays that occurred in 2014.
A net $12 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.
An $11 million increase in pension and postretirement benefit plan contributions.
A $7 million increase in property tax payments caused by both higher assessed property tax values and tax rates.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased $318 million in 2015, compared with 2014. The following items contributed to the increase:
A $137 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments, as $69 million was collected from customers in 2015 and $68 million was refunded to customers in 2014.
A $101 million increase 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 $69 million increase in income taxes refunds, pursuant to the tax allocation agreement with Ameren (parent), primarily related to deductions for accelerated depreciation and increased capital expenditures.
A $31 million increase in natural gas commodity costs collected from customers under the PGA.
A $26 million decrease in the cost of natural gas held in storage caused primarily by lower natural gas prices.
The following items partially offset the increase in Ameren Illinois’ cash from operating activities during 2015, compared with 2014:
A net $17 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.
A $12 million increase in pension and postretirement benefit plan contributions.
A $7 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.
Pension Plans
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 plans at a level equal to the greater of the pension cost or the legally required minimum contribution. ConsideringBased on Ameren’s assumptions at December 31, 2016,2017, its investment performance in 2016,2017, and its pension funding policy, Ameren expects to make annual contributions of $50less than $1 million to $70$60 million in each of the next five years, with aggregate estimated contributions of $290 million.$120 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 35% and 55%, respectively. These amounts are estimates. They may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In 2016,2017, Ameren contributed $57$64 million to its pension plans. See Note 1110 – 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 million during 2017, compared with 2016. Capital expenditures increased $56 million as a result of activity at Ameren Missouri and Ameren Illinois, discussed below. The $187 million increase in capital expenditures at Ameren Missouri and Ameren Illinois was partially offset by a $127 million decrease in 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, there was no cash used in investing activities associated with discontinued operations.
Ameren Missouri’s cash used 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 million in returns of net money pool advances compared with investing $125 million 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'sAmeren’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.
Ameren Missouri’s cash used in investing activities
increased by $210 million during 2016, compared with 2015. Capital expenditures increased $116 million, primarily related to electric distribution system reliability and energy center projects. Additionally, there was an increase in net advances to the money pool of $89 million.
Ameren Illinois’ cash used in investing activities increased by $5 million during 2016, compared with 2015, because of increased capital expenditures, primarily related to qualified investments in natural gas infrastructure under the QIP rider, storm restoration costs, and reliability.
2015 versus 2014
Ameren's cash used in investing activities associated with continuing operations increased by $95 million during 2015, compared with 2014. Capital expenditures increased $132 million, because of increased transmission expenditures, which included a $174 million increase at ATXI, primarily related to the Illinois Rivers project, and increased Ameren Illinois capital expenditures, partially offset by decreased expenditures at Ameren Missouri.
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. During 2014, cash provided by investing activities associated with Ameren’s discontinued operations consisted of $152 million received from Rockland Capital for the sale of the Elgin, Gibson City, and Grand Tower natural-gas-fired energy centers in January 2014, offset by payment of $13 million to IPH for the final working capital adjustment and certain liabilities associated with the New AER divestiture.
Ameren Missouri’s cash used in investing activities decreased by $113 million during 2015, compared with 2014. Capital expenditures decreased $125 million, primarily because several large projects were completed in 2014. Nuclear fuel expenditures decreased by $22 million because of the timing of purchases in 2015 compared with 2014. In addition, cash used in investing activities increased in 2015 because of net advances to the money pool of $36 million; there were no advances in 2014.
Ameren Illinois’ cash used in investing activities increased by $85 million during 2015, compared with 2014, because of increased capital expenditures, primarily for reliability and IEIMA projects.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2017, 2016, 2015, and 2014:2015:
|
| | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
Ameren(a) | $ | 2,076 |
| | $ | 1,917 |
| | $ | 1,785 |
|
| Ameren Missouri | 738 |
| | 622 |
| | 747 |
|
Ameren Illinois(b) | 924 |
| | 918 |
| | 835 |
|
|
| | | | | | | | | | | |
| | 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 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and the elimination of intercompany transfers. |
Ameren’s 2017 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $289 million primarily on the Illinois Rivers and Spoon River projects. Ameren Illinois spent $355 million on transmission projects, $153 million on projects that are recovered under the QIP rider, and $123 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 by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects.
| |
(b) | See Note 16 – Segment Information under Part II, Item 8, of this report for additional information on Ameren Illinois' capital expenditures by segment. |
Ameren’s 2016 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $416 million primarily on the Illinois Rivers project. Ameren Illinois spent $273 million on transmission projects and $109 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.
Ameren’s 2014 capital expenditures consisted of expenditures made by its subsidiaries including ATXI, which spent $201 million on the Illinois Rivers project. Ameren Missouri spent $101 million for electrostatic precipitator upgrades at its Labadie energy center, $33 million for the replacement of the nuclear reactor vessel head at its Callaway energy center, and $16 million for the construction of the O’Fallon energy center. Ameren Illinois spent $295 million on transmission projects and $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.
In December 2015, a federal tax law was enacted that authorized the continued use of bonus depreciation that allows for an acceleration of deductions for tax purposes. Bonus depreciation is expected to increase cash flow through at least 2020. Ameren expects to use this incremental cash flow to make capital investments in utility infrastructure for the benefit of its customers. Without these investments, the bonus depreciation would reduce rate base, which would reduce our revenue requirements and future earnings growth. The impact of bonus depreciation on Ameren Missouri, Ameren Illinois, and ATXI will vary based on investment levels at each company.
The following table presents Ameren'sAmeren’s estimate of capital expenditures that will be incurred from 20172018 through 2021,2022, 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.
| | | | 2017 | | 2018-2021 | | Total | 2018 | | 2019-2022 | | Total |
| Ameren Missouri | $ | 785 |
| | $ | 3,070 |
| - | $ | 3,395 |
| | $ | 3,855 |
| - | $ | 4,180 |
| $ | 845 |
| | $ | 3,310 |
| - | $ | 3,660 |
| | $ | 4,155 |
| - | $ | 4,505 |
|
| Ameren Illinois Electric Distribution | 480 |
| | 1,965 |
| - | 2,165 |
| | 2,445 |
| - | 2,645 |
| 465 |
| | 1,815 |
| - | 2,005 |
| | 2,280 |
| - | 2,470 |
|
| Ameren Illinois Natural Gas | 255 |
| | 1,110 |
| - | 1,225 |
| | 1,365 |
| - | 1,480 |
| 330 |
| | 1,220 |
| - | 1,350 |
| | 1,550 |
| - | 1,680 |
|
| Ameren Illinois Transmission | 375 |
| | 1,760 |
| | 1,950 |
| | 2,135 |
| | 2,325 |
| 470 |
| | 1,765 |
| - | 1,950 |
| | 2,235 |
| - | 2,420 |
|
| ATXI | 325 |
| | 240 |
| - | 265 |
| | 565 |
| - | 590 |
| 70 |
| | 215 |
| - | 240 |
| | 285 |
| - | 310 |
|
| Other | 5 |
| | 10 |
| - | 15 |
| | 15 |
| - | 20 |
| 5 |
| | 15 |
| - | 15 |
| | 20 |
| - | 20 |
|
| Ameren | $ | 2,225 |
| | $ | 8,155 |
| - | $ | 9,015 |
| | $ | 10,380 |
| - | $ | 11,240 |
| $ | 2,185 |
| | $ | 8,340 |
| - | $ | 9,220 |
| | $ | 10,525 |
| - | $ | 11,405 |
|
Ameren Missouri’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with environmental regulations. The estimates above 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. 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'sATXI’s estimated capital expenditures include expenditures for the three MISO-approved multi-value transmission projects. For additional information regarding the IEIMA capital expenditure requirements, the QIP rider, and ATXI'sATXI’s transmission projects, see Part I, Item 1, of this report.
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. 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 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, mercury, and CO2mercury emissions from its coal-fired energy centers. See Note 1514 – 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.
Cash Flows from Financing Activities
Cash provided by, or used in, financing activities is driven bya 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'sAmeren’s board of directors, and our long-term debt maturities, among other things.
2017 versus 2016
Ameren’s financing activities associated with continuing operations provided net cash of $102 million in 2017, compared with using net cash of $265 million in 2016. During 2017, Ameren utilized net proceeds from the issuance of $1,345 million of long-term indebtedness to repay $681 million of higher-cost long-term indebtedness, to repay $74 million of net commercial paper issuances, and to fund, in part, investing activities. In comparison, 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. 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, Ameren Missouri utilized net proceeds from the issuance of $438 million of 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, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In 2017, Ameren Missouri paid $362 million in dividends to Ameren (parent), compared with $355 million dividends paid in 2016. Additionally, during 2017, Ameren Missouri received $30 million in capital contributions from Ameren (parent) associated with the tax allocation agreement, compared to $44 million received in 2016.
Ameren Illinois’ cash provided by financing activities increased by $211 million in 2017, compared with 2016. During 2017, Ameren Illinois utilized net proceeds from the issuance of $507 million of long-term indebtedness and net commercial paper issuances to repay at maturity $250 million of higher-cost long-term indebtedness. In comparison, 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. Additionally, in 2017, no dividends were paid to Ameren (parent) compared to $110 million paid in 2016.
2016 versus 2015
Ameren'sAmeren’s financing activities associated with continuing operations used net cash of $265 million in 2016, compared with providing net cash of $232 million in 2015. The timingDuring 2016, Ameren utilized net proceeds from the issuance of short-term$646 million of long-term indebtedness and net commercial paper issuances to repay $395 million of higher-cost long-term debt issuances,indebtedness and to fund, in part, investing activities. In comparison, during 2015, Ameren utilized net proceeds from the issuance of their repayments, resulted in$1,197 million of long-term indebtedness to repay $413 million less cash provided by financing activitiesof net commercial paper issuances, $120 million of higher-cost long-term indebtedness, and to fund, in 2016, compared to 2015.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, primarily because2015. During 2016, Ameren Missouri utilized net proceeds from the issuance of a $149 million decreaseof 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 cash provided by short-term and long-term debt activity. This was partially offset by a $40 million decrease in cash paiddividends to Ameren (parent), net ofcompared with $575 million dividends paid in the year-ago period. Also, in 2016, Ameren Missouri received $44 million as a capital contributions received.contribution from Ameren (parent) compared to $224 million received in 2015.
Ameren Illinois'Illinois’ cash provided by financing activities decreased by $176 million in 2016, compared with 2015. Short-termDuring 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 debtindebtedness. 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 net of their repayments, resultedand to fund, in $39 million less cash provided by financing activitiespart, investing activities. Additionally, in 2016 compared with 2015. Additionally, there was aAmeren Illinois paid $110 million increase in dividends paid to Ameren (parent).
2015 versus 2014
Ameren's cash provided by financing activities associated with continuing operations increased $105 million compared to no dividends paid in 2015, compared with 2014. Short-term and long-term debt issuances, net of their repayments, resulted in $117 million more cash provided by financing activities in 2015, compared with 2014.
Ameren Missouri’s cash used in financing activities increased $212 million in 2015, compared with 2014, primarily because of a $201 million decrease in cash provided by net short-term and long-term debt activity. Additionally, cash paid to Ameren (parent), net of capital contributions received, increased $11 million.
Ameren Illinois' cash provided by financing activities decreased $163 million in 2015, compared with 2014, primarily because of a $175 million decrease in cash provided by net short-term and long-term debt activity, partially offset by a $10 million increase in capital contributions received from Ameren (parent).the year-ago period.
Credit Facility Borrowings and Liquidity
The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, or proceeds from short-term intercompanyaffiliate borrowings, drawings under the Credit Agreements, or commercial paper issuances. 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.
The following table presents Ameren'sAmeren’s consolidated liquidity as of December 31, 20162017:
| | | | | Available at December 31, 2016 | | Available at December 31, 2017 |
| Ameren and Ameren Missouri: | | | |
Ameren (parent) and Ameren Missouri (a): | | | |
Missouri Credit Agreement – borrowing capacity | | $ | 1,000 |
| | $ | 1,000 |
|
| Less: Ameren (parent) commercial paper outstanding | | 296 |
| | 224 |
|
| Less: Ameren Missouri commercial paper outstanding | | | 39 |
|
Missouri Credit Agreement – credit available | | 704 |
| | 737 |
|
| Ameren and Ameren Illinois: | | | |
Ameren (parent) and Ameren Illinois(b): | | | |
Illinois Credit Agreement – borrowing capacity | | 1,100 |
| | 1,100 |
|
| Less: Ameren (parent) commercial paper outstanding | | 211 |
| | 159 |
|
| Less: Ameren Illinois commercial paper outstanding | | 51 |
| | 62 |
|
| Less: Letters of credit | | 4 |
| | 1 |
|
Illinois Credit Agreement – credit available | | 834 |
| | 878 |
|
| Total Credit Available | | $ | 1,538 |
| | $ | 1,615 |
|
| Cash and cash equivalents | | 9 |
| | 10 |
|
| Total Liquidity | | $ | 1,547 |
| | $ | 1,625 |
|
| |
| (a) | The maximum aggregate amount available to Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $700 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. |
| |
| (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. |
In December 2016, Ameren, Ameren Missouri and Ameren Illinois amended, restated, and extended the maturity dates of theirThe Credit Agreements from December 2019, toprovide $2.1 billion of credit cumulatively through maturity in December 2021. The maturity date may be extended for two additional one-year periods upon mutual consent of the borrowers 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 scheduled to mature in December 2021, but the maturity date may be extended for two additional one-year periods upon mutual consent of the borrowers and lenders. The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren’sAmeren (parent),’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the Credit Agreementscredit agreements are available to Ameren (parent) to support issuances under Ameren’sAmeren (parent)’s commercial paper program, subject to borrowing sublimits.available credit capacity under the 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.
The following table presents the maximum aggregate amount available to each borrower under each facility:
|
| | | | | | | |
| | Missouri Credit Agreement | | Illinois Credit Agreement |
| Ameren | $ | 700 |
| | $ | 500 |
|
| Ameren Missouri | 800 |
| | (a) |
|
| Ameren Illinois | (a) |
| | 800 |
|
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'sAmeren’s utility subsidiaries is subject to approval by the FERC under the Federal Power Act. In February 2016, the FERC issued an order authorizing Ameren Missouri to issue up to $1 billion of short-term debt securities through March 2018. In August 2016, the FERC issued an order authorizing Ameren Illinois to issue up to $1 billion of short-term debt securities through September 2018. In July 2015,June 2017, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2017.2019. In 2016, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 2018 and through September 2018, respectively.
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 our issuances (net of issuance premiums or discounts), redemptions, repurchases, and maturities of long-term debt for the years ended December 31, 20162017, 20152016, and 20142015. The Ameren Companies did not issue any common stock or redeem or repurchase any preferred stock during the years ended 20162017, 20152016, and 20142015. In 2017, 2016, 2015 and 2014,2015, 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). For additional information related to the terms and uses of these issuances and effective registration statements, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.
| | | | Month Issued, Redeemed, Repurchased, or Matured | | 2016 | | 2015 | | 2014 | 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 |
| | $ | — |
| November | | $ | — |
| | $ | — |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | November | | — |
| | 350 |
| | — |
| November | | — |
| | — |
| | 350 |
|
| Ameren Missouri: | | | | | | | | | | | | |
| 3.50% Senior secured notes due 2024 | April | | — |
| | — |
| | 350 |
| |
| 3.65% Senior secured notes due 2045 | April | | — |
| | 249 |
| | — |
| April | | — |
| | — |
| | 249 |
|
| 3.65% Senior secured notes due 2045 | June | | 149 |
| | | | | June | | — |
| | 149 |
| | — |
|
| 2.95% Senior secured notes due 2027 | | June | | 399 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | | | | | | |
| 4.30% Senior secured notes due 2044 | June | | — |
| | — |
| | 248 |
| |
| 3.25% Senior secured notes due 2025 | December | | — |
| | — |
| | 300 |
| |
| 3.70% First mortgage bonds due 2047 | | November | | 496 |
| | — |
| | — |
|
| 4.15% Senior secured notes due 2046 | December | | 240 |
| | 248 |
| | — |
| 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 | | | $ | 389 |
| | $ | 1,197 |
| | $ | 898 |
| | | $ | 1,345 |
| | $ | 389 |
| | $ | 1,197 |
|
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | | | | | | | | |
| Ameren (parent): | | | | | | | |
| 8.875% Senior unsecured notes due 2014 | May | | $ | — |
| | $ | — |
| | $ | 425 |
| |
| Ameren Missouri: | | | | | | | | | | | | |
| 5.40% Senior secured notes due 2016 | February | | 260 |
| | | | | February | | — |
| | 260 |
| | — |
|
| 4.75% Senior secured notes due 2015 | April | | — |
| | 114 |
| | — |
| April | | — |
| | — |
| | 114 |
|
| 5.50% Senior secured notes due 2014 | May | | — |
| | — |
| | 104 |
| |
| 6.40% Senior secured notes due 2017 | | June | | 425 |
| | — |
| — | — |
|
| City of Bowling Green capital lease (Peno Creek CT) | December | | 6 |
| | 6 |
| | 5 |
| December | | 6 |
| | 6 |
| | 6 |
|
| Ameren Illinois: | | | | | | | | | | | | |
5.90% Series 1993 due 2023(a) | January | | — |
| | — |
| | 32 |
| |
5.70% 1994A Series due 2024(a) | January | | — |
| | — |
| | 36 |
| |
| 5.95% 1993 Series C-1 due 2026 | January | | — |
| | — |
| | 35 |
| |
| 5.70% 1993 Series C-2 due 2026 | January | | — |
| | — |
| | 8 |
| |
| 5.40% 1998A Series due 2028 | January | | — |
| | — |
| | 19 |
| |
| 5.40% 1998B Series due 2028 | January | | — |
| | — |
| | 33 |
| |
| 6.20% Senior secured notes due 2016 | June | | 54 |
| | — |
| | — |
| June | | — |
| | 54 |
| | — |
|
| 6.25% Senior secured notes due 2016 | June | | 75 |
| | — |
| | — |
| June | | — |
| | 75 |
| | — |
|
| 6.125% Senior secured notes due 2017 | | November | | 250 |
| | — |
| | — |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 395 |
| | $ | 120 |
| | $ | 697 |
| | | $ | 681 |
| | $ | 395 |
| | $ | 120 |
|
(a) Less than $1In June 2017, Ameren Missouri issued $400 million of 2.95% senior secured notes due June 2027, with interest payable semiannually on June 15 and December 15 of each year, beginning December 15, 2017. Ameren Missouri 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 bonds remain outstanding after redemption.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 2015,1 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 issuance of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing. It will expirefiling and expires in June 2018.December 2020.
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.
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, 2016,2017, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation.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, and in certain of the Ameren Companies’ indentures and articles of incorporation.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’s, Ameren Missouri's,Missouri’s, and Ameren Illinois'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 and Return of Capital
Ameren paid to its shareholders common stock dividends totaling $416$431 million,, or $1.715$1.778 per share, in 2016, $4022017, $416 million,, or $1.655$1.715 per share, in 2015,2016, and $390$402 million,, or $1.610$1.655 per share, in 2014.2015.
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren'sAmeren’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 10, 2017,9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 4445.75 cents per share, payable on March 31, 2017,29, 2018, to shareholders of record on March 14, 2017.2018.
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 relatedwith 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 its 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 may not pay any dividend on its stock unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.
At December 31, 2016,2017, the amount of restricted net assets of Ameren'sAmeren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $2.1$2.3 billion.
The following table presents common stock dividends paid by Ameren Corporation to its common shareholders and by Ameren Missouri and Ameren Illinois to their parent, Ameren:
| | | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Ameren | | $ | 431 |
| | $ | 416 |
| | $ | 402 |
|
| Ameren Missouri | $ | 355 |
| | $ | 575 |
| (a) | $ | 340 |
| 362 |
| | 355 |
| | 575 |
|
| Ameren Illinois | 110 |
| | — |
| | — |
| — |
| | 110 |
| | — |
|
| Ameren | 416 |
| | 402 |
| | 390 |
| |
| |
(a) | Additionally, during 2014, Ameren Missouri returned capital of $215 million to Ameren (parent). |
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, 20162017. See Note 1110 – 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 amounts 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 | Less Than 1 Year | | 1 – 3 Years | | 3 – 5 Years | | After 5 Years | | Total |
Ameren:(a) | | | | | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 681 |
| | $ | 1,421 |
| | $ | 450 |
| | $ | 4,774 |
| | $ | 7,326 |
| $ | 841 |
| | $ | 1,023 |
| | $ | 514 |
| | $ | 5,617 |
| | $ | 7,995 |
|
Interest payments(c) | 502 |
| | 841 |
| | 737 |
| | 4,678 |
| | 6,758 |
| 464 |
| | 855 |
| | 814 |
| | 5,018 |
| | 7,151 |
|
Operating leases(d) | 13 |
| | 24 |
| | 21 |
| | 23 |
| | 81 |
| |
Other obligations(e) | 1,258 |
| | 1,408 |
| | 377 |
| | 829 |
| | 3,872 |
| |
| Operating leases | | 10 |
| | 17 |
| | 12 |
| | 14 |
| | 53 |
|
Other obligations(d) | | 981 |
| | 964 |
| | 206 |
| | 254 |
| | 2,405 |
|
| Total cash contractual obligations | $ | 2,454 |
| | $ | 3,694 |
| | $ | 1,585 |
| | $ | 10,304 |
| | $ | 18,037 |
| $ | 2,296 |
| | $ | 2,859 |
| | $ | 1,546 |
| | $ | 10,903 |
| | $ | 17,604 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 431 |
| | $ | 964 |
| | $ | 100 |
| | $ | 2,524 |
| | $ | 4,019 |
| $ | 384 |
| | $ | 673 |
| | $ | 64 |
| | $ | 2,867 |
| | $ | 3,988 |
|
Interest payments(c) | 352 |
| | 616 |
| | 552 |
| | 3,431 |
| | 4,951 |
| 331 |
| | 592 |
| | 575 |
| | 3,208 |
| | 4,706 |
|
Operating leases(d) | 11 |
| | 22 |
| | 19 |
| | 21 |
| | 73 |
| |
Other obligations(e) | 751 |
| | 933 |
| | 235 |
| | 370 |
| | 2,289 |
| |
| Operating leases | | 8 |
| | 15 |
| | 12 |
| | 14 |
| | 49 |
|
Other obligations(d) | | 628 |
| | 654 |
| | 163 |
| | 194 |
| | 1,639 |
|
| Total cash contractual obligations | $ | 1,545 |
| | $ | 2,535 |
| | $ | 906 |
| | $ | 6,346 |
| | $ | 11,332 |
| $ | 1,351 |
| | $ | 1,934 |
| | $ | 814 |
| | $ | 6,283 |
| | $ | 10,382 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
Long-term debt(b) | $ | 250 |
| | $ | 457 |
| | $ | — |
| | $ | 1,900 |
| | $ | 2,607 |
| $ | 457 |
| | $ | — |
| | $ | 400 |
| | $ | 2,000 |
| | $ | 2,857 |
|
Interest payments(c) | 129 |
| | 181 |
| | 152 |
| | 1,195 |
| | 1,657 |
| 106 |
| | 188 |
| | 185 |
| | 1,584 |
| | 2,063 |
|
Operating leases(d) | 1 |
| | 2 |
| | 2 |
| | 1 |
| | 6 |
| |
Other obligations(e) | 464 |
| | 463 |
| | 142 |
| | 444 |
| | 1,513 |
| |
| Operating leases | | 1 |
| | — |
| | — |
| | 1 |
| | 2 |
|
Other obligations(d) | | 352 |
| | 310 |
| | 43 |
| | 40 |
| | 745 |
|
| Total cash contractual obligations | $ | 844 |
| | $ | 1,103 |
| | $ | 296 |
| | $ | 3,540 |
| | $ | 5,783 |
| $ | 916 |
| | $ | 498 |
| | $ | 628 |
| | $ | 3,625 |
| | $ | 5,667 |
|
| |
| (a) | Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations. |
| |
| (b) | Excludes unamortized discount and premium and debt issuance costs of $50$60 million, $2527 million, and $19$27 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, 20162017. |
| |
| (d) | Amounts for certain land-related leases have indefinite payment periods. The annual obligation of $3 million, $2 million, and $1 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, for these items is included in the Less than 1 Year, 1 – 3 Years, and 3 – 5 Years columns. See Leases in Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for additional information.
|
| |
(e) | See Other Obligations in Note 1514 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein. |
As of December 31, 2016,2017, Ameren, Ameren Missouri, and Ameren Illinois had no unrecognized tax benefits (detriments) for uncertain tax positions.
Off-Balance-Sheet Arrangements
At December 31, 2016,2017, 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, letters of credit, and Ameren parent(parent) guarantee arrangements on behalf of its subsidiaries. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
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+ |
| 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, was $12 million at Ameren and Ameren Missouri at December 31, 2016. Cashcash collateral posted by external parties with Ameren, Ameren Missouri, and Ameren Illinois were immaterial at December 31, 2016.2017. A sub-investment-grade issuer or senior unsecured debt rating (whether below “BBB-” from S&P or below “Baa3” from Moody's)Moody’s) at December 31, 2016,2017, 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 $80$82 million, $54$44 million, and $26$38 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2016,2017, if market prices were 15% higher or lower than December 31, 20162017, 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'scompany’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 are seekingseek 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 are seeking to align our overall spending, both operating and capital, with economic conditions and with regulatorythe frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We are focusedfocus on minimizing the gap between allowed and earned returns on equity and intend to allocateallocating capital resources to our business opportunities that we expect towill offer the most attractive risk-adjusted return potential.
As a part of Ameren'sAmeren’s strategic plan, we are pursuingpursue projects to meet our customer energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories, as well as evaluatingterritories. Ameren also evaluates competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO as they arise. Additionally, Ameren Missouri willexpects 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 aremay reasonably likely to affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 20172018 and beyond.
Operations
Ameren continues to invest in FERC-regulated electric transmission. MISOATXI has approved three electric transmissionMISO-approved multi-value projects, to be developed by ATXI.the Illinois Rivers, Spoon River, and Mark Twain projects. The Illinois Rivers project involves the construction of a transmission line from western Indianaeastern
Missouri across the state of Illinois to eastern Missouri. Thewestern Indiana. Construction activities for the Illinois Rivers project are continuing on schedule, and the last section of this project is expected to be completed by the end of 2019. The Spoon River project, located in northwest Illinois, and thewas placed in service in February 2018. The Mark Twain project, located in northeast Missouri areand connecting the other two MISO-approved projectsIllinois Rivers project to be constructed by ATXI. Construction activities for the Spoon River project are continuing on schedule and the projectIowa, is expected to be completed in 2018. The Illinois Riversby the end of 2019. See Note 2 – Rate and the Spoon River projects have received allRegulatory Matters under Part II, Item 8, of the necessary approvals to authorize their construction. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessitythis report for information regarding the Mark Twain project and its approval process and the Illinois Rivers project. Before starting construction, ATXI must obtain assents for road crossings from the five counties where the line will be constructed. NoneAs of the five county commissions have approvedDecember 31, 2017, ATXI’s requests for the assents. ATXI is planning to complete the project in 2019; however, further delays in obtaining the assents could delay the completion date. The totalexpected remaining investment in all three projects is expectedapproximately $300 million, with the total investment to be more than $575 million from 2017 through 2019.$1.6 billion. In addition, Ameren Illinois expects to invest $2.2$2.3 billion in electric transmission assets from 20172018 through 20212022 to replace aging infrastructure and improve reliability.
Both 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 the rates that became effective on January 1, 2017,expected rate base growth and the currently allowed 10.82% return on common equity, the 20172018 revenue requirementrequirements for Ameren Illinois’ electric transmission business would be $258 million. The 2017 revenue requirement represents a $33 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.4 billion. Based on the rates that became effective on January 1, 2017, and the currently allowed 10.82% return on equity, the 2017 revenue requirement for ATXI’s electric transmission business would be $171 million. The 2017businesses are $270 million and $174 million, respectively. These revenue requirement represents a $44requirements represent an increase in Ameren Illinois' and ATXI's revenue requirements of $11 million increase overand $4 million, respectively, primarily because of the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 56.3% common equity and a projected average rate base of $1.1 billion, reflecting additional investment ingrowth described above, partially offset by a decrease due to the Illinois Rivers project.lower federal statutory corporate income tax rates enacted under the TCJA.
The return on common equity was the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each challenged the allowed base return on common equity for MISO transmission owners, including Ameren Illinois and ATXI. In September 2016,ATXI, was the FERC issuedsubject of a final order in
the November 2013FERC complaint case filed in February 2015 which loweredchallenged the allowed base return on common equity to 10.32%, or a 10.82%equity. Ameren Illinois and ATXI currently use the FERC authorized total return on common equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. The order was consistent with the initial decision an administrative law judge issued in December 2015, and requires customer refunds, with interest, to be issued for the 15-month period ended February 2015. In addition, the new allowed return on common equity is reflectedof 10.82% in rates prospectively from the September 2016 effective date of the order. Refunds for the November 2013 complaint case are expected to be issued in the first half of 2017.In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved bycustomer rates. A final FERC would lower the allowed base return on common equity to 9.70%, or a 10.20% total return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. It would also require the issuance of customer refunds, with interest, for the 15-month period ended May 2016.The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. That final order will determine the allowed return on common equity for the 15-month period ended May 2016. That final order will alsowould establish the allowed return on common equity that will applyto be applied to the 15-month period from February 2015 to May 2016 and also establish the return on common equity to be included in customer rates prospectively from its expected second quarter 2017the 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 which became effective in September 2016.that may be ordered as a result of the complaint case is uncertain. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren'sAmeren’s and Ameren Illinois'Illinois’ annual earnings by an estimated $7$8 million and $4 million, respectively, based on each company’s 20172018 projected rate base. AmerenSee Note 2 – Rate and Ameren Illinois recorded current regulatory liabilities on their respective December 31, 2016 balance sheets, representing their estimateRegulatory Matters under Part II, Item 8, of the expected refunds.this report for information regarding FERC complaint cases.
In July 2016, Ameren Missouri filed a request withMarch 2017, the MoPSC seeking approval to increase its annual revenues for electric service. Relating to that request, in February 2017, Ameren Missouri, the MoPSC staff, the MoOPC, and all intervenors filedissued an order approving a unanimous stipulation and agreement with the MoPSC.in Ameren Missouri’s July 2016 regulatory rate review. The stipulation and agreement, which is subject to MoPSC approval, would resultorder resulted in a $3.4$3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared to itswith the prior revenue requirement established in the MoPSC'sMoPSC’s April 2015 electric rate order. The stipulationnew rates, base level of expenses, and agreement did not specify the common equity percentage, the rate base, or the allowed returnamortizations became effective on common equity.April 1, 2017.The new revenue requirement reflects the current actual sales volumes of the New Madrid Smelter, whose operations remain suspended, as well as other agreed upon sales volumes. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs under the stipulation and agreement would decreasedecreased by $54 million from the base level established in the MoPSC'sMoPSC’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, would reducereduced expenses by $26$26 million from the base levels established in the MoPSC'sMoPSC’s April 2015 electric rate order.
The stipulation and agreement contemplatesIn December 2017, the ICC issued an order in Ameren Illinois’ annual update filing that new rates will become effective on or before March 20, 2017.approved a
In the first quarter of 2016, Noranda, which was historically $17 million decrease in Ameren Missouri's largest customer, suspended operations at the New Madrid Smelter and filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. Operations at the New Madrid Smelter remain suspended, and Ameren Missouri is uncertain of future sales to the smelter. As a result, Ameren Missouri will not fully recover itsIllinois’ electric delivery service revenue requirement until rates are adjusted prospectively by the MoPSC to accurately reflect the actual sales volumes to the New Madrid Smelter. Based on the unanimous stipulation and agreement filed with the MoPSCbeginning in February 2017, electric rates are expected to be adjusted in March 2017 to accurately reflect the smelter’s actual sales volumes.
The IEIMAJanuary 2018. However, Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and investment return in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois' 2017Illinois’ 2018 electric distribution service revenues will be based on its 20172018 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA'sIllinois performance-based formula ratemaking framework. The 20172018 revenue requirement is expected to be higher thancomparable to the 20162017 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of 5.25%approximately 5%, and an expected increase in the monthly average yield of 30-year United States treasury bonds.Treasury bonds, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA. The 2018 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2020. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7$8 million change in Ameren'sAmeren’s and Ameren Illinois'Illinois’ net income, based on its 2017 projected rate base.
In December 2016, the ICC issued an order with respect to Ameren Illinois’ annual update filing. 2018 projected year-end rate base.
The ICC approved a $14 million decrease in Ameren Illinois’ electric distribution service revenue requirement that began in January 2017. These rates have affected, and will continue to affect, Ameren Illinois' cash receipts during 2017, but will not affect its electric distribution service operating revenues, which will instead be determined by Ameren Illinois' recoverable costs, rate base, common equity percentage, and the monthly average of the United States treasury bonds in 2017. The 2017 revenue requirement reconciliation, as discussed above, is expected to result in a regulatory asset that will be collected from customers in 2019.
Beginning as early as June 2017, the FEJA will allowallows Ameren Illinois to earn a return on its electric energy efficiencyenergy-efficiency program investments. Ameren IllinoisIllinois’ electric energy efficiencyenergy-efficiency investments will beare deferred as a regulatory asset and will earn a return at the company’s weighted averageweighted-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 efficiencyenergy-efficiency investments can also be increased or decreased by up to 200 basis points, baseddepending on the achievement of annual energy savings goals. ThePursuant to the FEJA, increased the level of electric energy efficiency saving targets through 2030. Based on a formula provided in the act, Ameren Illinois estimates it can annuallyplans to invest up to $100$99 million per year in electric energy-efficiency programs from 2018 through 2021 upthat will earn a return.Ameren Illinois plans to $107 million annuallymake similar yearly investments in electric energy-efficiency programs from 2022 through 2025, and up to $114 million annually from 2026 through 2030. The ICC has the ability to lower thereduce electric energy efficiency savingenergy-efficiency savings goals if there are insufficient cost effective measures available.cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy efficiencyenergy-efficiency program investments and the return on those investments will be recoveredcollected from customers through a rider, andrider; they will not be included in the IEIMA formula rate process.ratemaking framework. See Note 2 – Rate and
Beginning in 2017,
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 FEJA decouples electric distributionICC seeking approval to increase its annual revenues established infor 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 proceeding from actual sales volumes by providing that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes reflected in that year's rates will be collected from or refunded to customers within two years.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'sMissouri’s next scheduled refueling and maintenance outage at its Callaway energy center will be in fallis scheduled for the spring of 2019. During the 2017 andrefueling, Ameren Missouri expects to incur $32 million ofincurred maintenance expenses which approximates the cost of the spring 2016 outage.$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'sMissouri’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.
As we continue to experience cost increases and to make infrastructure investments, In addition, Ameren Missouri may incur increased nonnuclear energy center maintenance costs in non-outage years.
Ameren and Ameren IllinoisMissouri expect to seek regular electrican approximately $15 million decrease in annual interest charges as a result of the repayment of $425 million of Ameren Missouri’s 6.40% senior secured notes at maturity and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators.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 Illinois will also seek 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, increased customer use of innovative and increasingly cost-effective technological advances including private generation and storage, increased investments and expected future investments for environmental compliance, system reliability improvements, and new generation capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs and higher property taxes, among other costs.Missouri’s annual interest charges.
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| • | As we continue to make infrastructure investments and to experience cost increases, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek 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 storage. However, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy as a means to address CO2 emission concerns. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, result in rate base earnings 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. |
For additional information regarding recent rate orders,
lawsuits, and related appeals and pending requests filed with state and federal regulatory commissions, including the February 2017 unanimous stipulation and agreement filed with the MoPSC that settles Ameren Missouri's July 2016 electric rate case, see Note 2 – Rate and Regulatory Matters and Note 10 – Callaway Energy Center 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 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. The new wind generation facilities are expected to be located in Missouri and neighboring states. The source, location, and cost of the new wind generation, among other items, remain subject to reaching agreements with developers. 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 as energy prices; Ameren Missouri’s ability to obtain timely interconnection agreements with MISO or other RTOs, including the cost of such interconnections; 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.
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| • | In connection with the integrated resource plan 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 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. |
Through 2021,2022, 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 in total up to $11.2$11.4 billion (Ameren Missouri – up to $4.2$4.5 billion; Ameren Illinois – up to $6.4$6.6 billion; ATXI – up to $0.6$0.3 billion) of capital expenditures during the period from 20172018 through 2021.2022. These estimates do not reflect the potential additional investments identified in Ameren Missouri’s integrated resource plan discussed above, 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.
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| • | 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. These costs could be prohibitive, whichCertain of these regulations are being challenged through litigation or are being reviewed by the EPA, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri'sMissouri’s coal-fired energy centers. Ameren Missouri'sMissouri’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'sAmeren’s and Ameren Missouri'sMissouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in rates charged to customers.customer rates. |
In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until the legal appeals are concluded. If the rule is ultimately upheld and not rescinded or altered significantly by the new federal administration, Ameren Missouri expects to incur increased net fuel and operating costs, and make new or accelerated capital expenditures, in addition to the costs of making modifications to existing operations in order to achieve compliance. Compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could result in increased operating costs.
Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three years and will file its next plan in 2017. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, was a 20-year plan that supported a more diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, hydro and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as those energy centers reach the end of their useful lives, expanding customer energy efficiency programs, and adding natural gas-fired combined cycle generation.
The Ameren Companies have multiyear credit agreements
that cumulatively provide $2.1 billion of credit through December 2021, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. 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 2018, $8032019, $951 million and $707$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 outstanding short-term debt with long-term debt in 2017.2018 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.
In December 2015,Federal income tax legislation enacted under the TCJA will 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 in 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 law was enacted that authorized the continued use of bonus depreciation which allows for an acceleration of deductions for tax purposes at a rate of 50% through 2017. The rate will be reduced to 40% in 2018 and then to 30% in 2019. Bonus depreciation will be phased out in 2020 unless a new law is enacted. Based on existing tax laws, bonus depreciation is expected to reduce or eliminate federalbe 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 through at least 2020. 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 to use this incrementala decrease in operating cash flow to make capital investmentsflows 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 utility infrastructure for the benefit of its customers. Without these investments, bonus depreciation would reduce rate base which reduces our revenue requirements and future earnings growth. The impact of bonus depreciation onapproximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Companies will vary based on investment levels at each company.Illinois – $0.5 billion).
As of December 31, 2016,2017, Ameren had $539$235 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $37 million and Ameren Illinois – $137 million) and $130$120 million in federal and state income tax credit carryforwards. These carryforwards (Ameren Missouri – $29 million and Ameren Illinois – $1 million). In addition, Ameren has $35 million ofare expected stateto partially offset income tax refunds and state overpayments.obligations until 2021, at which time Ameren expects to begin making material income tax payments. Consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities for Ameren Missouri through 2017 and Ameren Illinois until 2021. Based on existing tax laws, Ameren does not expect to makebegin making material federal income tax payments until 2021. These tax benefits, primarily at theto Ameren (parent) level, when realized, would be available to support funding Ameren Transmission investments.beginning in 2018.
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 and expects to use debt to fund such cash shortfalls; it does not currently expect to issue equitydo so over the next severalfive years. Additionally, Ameren may be required to issue incremental debt and/or equity, 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.
The above items could have a material impact on our results of operations, financial position, orand liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance
our results of operations, financial position, orand liquidity. These strategies may include acquisitions, divestitures, and opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren'sAmeren’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, 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 delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking processframework
Ameren Illinois’ and ATXI'sATXI’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 processframeworks
Ameren Missouri'sMissouri’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. 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. Ameren Illinois estimates its annual revenue requirement pursuant to the IEIMA for interim periods by using internal forecasted information, such as projected operations and maintenance expenses, depreciation expense, taxes other than income taxes, and rate base, as well asand published forecasted data regarding that year'syear’s 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'syear’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 costs incurred, investments made or orders by the ICC or courts can result in a subsequent change in Ameren Illinois'Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates lost revenues resulting from its MEEIA customer energy efficiencyenergy-efficiency programs. Ameren Missouri uses a 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. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for 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 1110 – 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 1110 – 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 109 – Callaway Energy Center and Note 1514 – 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 1312 – 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
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, including a change in forecasted financial condition and/or results of operations, change in income tax laws, enacted tax rates or amounts subject to income tax, the form, structure, and timing of asset or stock sales or dispositions, changeschange in the regulatory treatment of any tax reform benefits, and results of 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 1312 – Income Taxes under Part II, Item 8, of this report for the amount of deferred tax assets and uncertain tax positionsincome taxes recorded at December 31, 20162017.
Unbilled Revenue
At the end of each period, Ameren, Ameren Missouri, and Ameren Illinois estimate 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 reflects 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 valued 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. See the balance sheet for each of the Ameren Companies under Part II, Item 8, of this report for unbilled revenue amounts.
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 transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois participates in the performance-based formula ratemaking processframeworks established pursuant to the IEIMA and the FEJA for its electric distribution business.business and its electric energy-efficiency investments. 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 FEJA formula ratemaking frameworks, the monthly average yields of 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the earnings ofannual return on equity applicable to Ameren Illinois’ electric distribution business.business and electric energy-efficiency investments. Ameren Illinois and ATXI use a company-specific, forward-looking rate 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 April 2015March 2017 MoPSC electric rate order approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude
excludes substantially all transmission revenues and substantially all transmission charges. Ameren Missouri is therefore exposed to transmission charges to the extent that they exceed transmission revenues. 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.
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| 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 directorsdirectors’ 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 defined pension and postretirement benefit plans.plans, asset retirement obligations, and goodwill.
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 one hundred100 basis points on variable-rate debt outstanding at December 31, 2016:2017:
| | | | | Interest Expense | | Net Income(a) | | Interest Expense | | Net Income(a) |
| Ameren | $ | 8 |
| $ | (5 | ) | $ | 7 |
| $ | (5 | ) |
| Ameren Missouri | | 2 |
| | (1 | ) | | 2 |
| | (2 | ) |
| Ameren Illinois | | 1 |
| | (b) |
| | 1 |
| | (1 | ) |
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| (a) | Calculations are based on an estimatedthe 2018 statutory tax raterates of 37%27%, 38%25%, and 38%28% for Ameren, Ameren Missouri, and Ameren Illinois, respectively. |
Ameren Illinois’ annualThe return on equity component under the formula ratemaking process for its electric distribution businessIEIMA and the FEJA is directly correlatedequal to the calendar year average of the monthly yields of 30-year United States Treasury bonds plus 580 basis pointspoints. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworks for a calendar year. Theboth its electric distribution service and its electric energy-efficiency investments is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. A 50
basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7$8 million change in Ameren'sAmeren’s and Ameren Illinois'Illinois’ net income, based on its 20172018 projected rate base.
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, 2016.2017.
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, 2016,2017, 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'ssupplier’s receivables relating to Ameren Illinois'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 reflectingto reflect charges for electric distribution and purchased receivables. As of December 31, 2016,2017, Ameren Illinois'Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $31 million. The risk associated with Ameren Illinois'Illinois’ electric and natural gas trade receivables is also mitigated by a rate 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. 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.
EquityInvestment 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 20172018 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, 2016,2017, this fund was invested in domestic equity securities (67%(66%) and debt securities (32%(33%). 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. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates. 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 hasand Ameren Illinois have company-owned life insurance contracts. These life insurance contracts include equitywith net asset values of $136 million and debt investments that are exposed to price fluctuations in equity markets and to changes in interest rates.$9 million, respectively, as of December 31, 2017.
Commodity Price Risk
With regard to Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businesses exposure to changing market prices 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 a fuel and purchased power cost recovery mechanism that allows it to recover or refund, through customer rates, 95% of changesthe variance in net energy costs greater or less thanfrom the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews. Ameren Missouri remains exposed to the remaining 5% of such changes.
Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its customers. 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. Ameren Illinois does not generate earnings based on the resale of power but rather on the delivery of energy. Ameren Illinois purchases power primarily through MISO, with additional procurement events administered by the IPA. The IPA has proposed and the ICC has approved multiple procurement events covering portions of years through 2019.2020. In 2016,2017, acting in its role as the provider of last resort, Ameren Illinois supplied power for 23% of its kilowatthour sales to its electric customers. Ameren Illinois expects full recovery of its purchased power costs.
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 rate proceeding, subject to prudence review.
With regardOur exposure to our exposure for commodity price risk for construction and maintenance activities Ameren is exposedrelated 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 1514 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.
Commodity Supplier Risk
The use of ultra-low-sulfur coal is part of Ameren Missouri'sMissouri’s environmental compliance strategy. Ameren Missouri has agreements with multiple suppliers to purchase ultra-low-sulfur coal through 20202021 to comply with environmental regulations. The coal contracts are with a single supplier through 2017, and with multiple suppliers beyond 2017. Disruptions to the deliveries of ultra-low-sulfur coal from a supplier could compromise Ameren Missouri'sMissouri’s ability to operate in compliance with emission standards. The suppliers of ultra-low-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-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of ultra-low-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 of a design fabricated by only a single supplier. That supplierWestinghouse, which is currently the only NRC-licensed supplier ableauthorized to provide fuel assemblies to the Callaway energy center. IfDuring 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
should decide 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 toa change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center up tocould take an estimated three years of analysis and NRC licensing effort would be requiredefforts to fully implement such a change.
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, 2016.2017. 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 | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fair value of contracts at beginning of year, net | $ | (27 | ) | | $ | (219 | ) | | $ | (246 | ) | $ | (4 | ) | | $ | (180 | ) | | $ | (184 | ) |
| Contracts realized or otherwise settled during the period | 13 |
| | 44 |
| | 57 |
| (3 | ) | | 4 |
| | 1 |
|
| Fair value of new contracts entered into during the period | 9 |
| | 4 |
| | 13 |
| 11 |
| | (7 | ) | | 4 |
|
| Other changes in fair value | 1 |
| | (9 | ) | | (8 | ) | 4 |
| | (34 | ) | | (30 | ) |
| Fair value of contracts outstanding at end of year, net | $ | (4 | ) | | $ | (180 | ) | | $ | (184 | ) | $ | 8 |
| | $ | (217 | ) | | $ | (209 | ) |
The following table presents maturities of derivative contracts as of December 31, 2016,2017, 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 | 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 | $ | (4 | ) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | (3 | ) | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Level 2(a) | (1 | ) | | (5 | ) | | — |
| | — |
| | (6 | ) | (3 | ) | | (3 | ) | | — |
| | — |
| | (6 | ) |
Level 3(b) | 8 |
| | (3 | ) | | — |
| | — |
| | 5 |
| 8 |
| | 2 |
| | — |
| | — |
| | 10 |
|
| Total | $ | 3 |
| | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | (4 | ) | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Ameren Illinois: |
| |
| |
| |
| |
|
|
| |
|
| |
|
| |
|
| |
|
|
| Level 1 | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2 |
| $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) |
Level 2(a) | 7 |
| | (3 | ) | | — |
| | — |
| | 4 |
| (10 | ) | | (7 | ) | | (1 | ) | | — |
| | (18 | ) |
Level 3(b) | (13 | ) | | (26 | ) | | (28 | ) | | (119 | ) | | (186 | ) | (14 | ) | | (30 | ) | | (29 | ) | | (125 | ) | | (198 | ) |
| Total | $ | (4 | ) | | $ | (29 | ) | | $ | (28 | ) | | $ | (119 | ) | | $ | (180 | ) | $ | (25 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (217 | ) |
| Ameren: | | | | | | | | | | | | | | | | | | |
| Level 1 | $ | (2 | ) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | (1 | ) | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
Level 2(a) | 6 |
| | (8 | ) | | — |
| | — |
| | (2 | ) | (13 | ) | | (10 | ) | | (1 | ) | | — |
| | (24 | ) |
Level 3(b) | (5 | ) | | (29 | ) | | (28 | ) | | (119 | ) | | (181 | ) | (6 | ) | | (28 | ) | | (29 | ) | | (125 | ) | | (188 | ) |
| Total | $ | (1 | ) | | $ | (36 | ) | | $ | (28 | ) | | $ | (119 | ) | | $ | (184 | ) | $ | (17 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (209 | ) |
| |
(a) | Principally fixed-price vs. floating over-the-counterOTC power swaps, power forwards, and fixed-price vs. floating over-the-counterOTC 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:
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 as of December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2017, 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, 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 listed in the index appearing under Item 15(a)(1)referred to above present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries (the "Company") atthe Company as of December 31, 20162017 and 2015,2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016,2017, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016,2017, based on criteria established in Internal Control –- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, and financial statement schedules, 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 thesethe Company’s consolidated financial statements on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated 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 Public Company Accounting Oversight Board (United States).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 supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 20172018
We have served as the Company’s auditor since at least 1932. We have not determined 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:
In our opinion,Opinion on the Financial Statements
We have audited the accompanying balance sheets of Union Electric Company as of December 31, 2017 and 2016, 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, including the related notes and financial statementsstatement schedule listed in the index appearing under Item 15(a)(1)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Union Electricthe Company (the "Company") atas of December 31, 20162017 and 2015,2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016,2017, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements.
Basis for Opinion
Thesefinancial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these the Company’sfinancial statements and financial statement schedule 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 Public Company Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2017
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Illinois Company (the "Company") at December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).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. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof 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 supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 20172018
We have served as the Company’s auditor since at least 1932. We have not determined 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:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ameren Illinois Company as of December 31, 2017 and 2016, 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, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018
We have served as the Company’s auditor since 1998.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (In millions, except per share amounts) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (In millions, except per share amounts) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (In millions, except per share amounts) |
| | | Year Ended December 31, | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Operating Revenues: |
| |
| | |
| |
| | |
| Electric | $ | 5,196 |
| | $ | 5,180 |
| | $ | 4,913 |
| $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
|
| Natural gas | 880 |
| | 918 |
| | 1,140 |
| 867 |
| | 880 |
| | 918 |
|
| Total operating revenues | 6,076 |
| | 6,098 |
| | 6,053 |
| 6,177 |
| | 6,076 |
| | 6,098 |
|
| Operating Expenses: |
| |
| | |
| |
| | |
| Fuel | 745 |
| | 878 |
| | 826 |
| 737 |
| | 745 |
| | 878 |
|
| Purchased power | 621 |
| | 514 |
| | 461 |
| 638 |
| | 621 |
| | 514 |
|
| Natural gas purchased for resale | 341 |
| | 415 |
| | 615 |
| 311 |
| | 341 |
| | 415 |
|
| Other operations and maintenance | 1,676 |
| | 1,694 |
| | 1,684 |
| 1,660 |
| | 1,676 |
| | 1,694 |
|
| Provision for Callaway construction and operating license (Note 2) | — |
| | 69 |
| | — |
| |
| Provision for Callaway construction and operating license | | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 845 |
| | 796 |
| | 745 |
| 896 |
| | 845 |
| | 796 |
|
| Taxes other than income taxes | 467 |
| | 473 |
| | 468 |
| 477 |
| | 467 |
| | 473 |
|
| Total operating expenses | 4,695 |
| | 4,839 |
| | 4,799 |
| 4,719 |
| | 4,695 |
| | 4,839 |
|
| Operating Income | 1,381 |
| | 1,259 |
| | 1,254 |
| 1,458 |
| | 1,381 |
| | 1,259 |
|
| Other Income and Expenses: | | | | | | | | | | |
| Miscellaneous income | 74 |
| | 74 |
| | 79 |
| 59 |
| | 74 |
| | 74 |
|
| Miscellaneous expense | 32 |
| | 30 |
| | 22 |
| 21 |
| | 32 |
| | 30 |
|
| Total other income | 42 |
| | 44 |
| | 57 |
| 38 |
| | 42 |
| | 44 |
|
| Interest Charges | 382 |
| | 355 |
| | 341 |
| 391 |
| | 382 |
| | 355 |
|
| Income Before Income Taxes | 1,041 |
| | 948 |
| | 970 |
| 1,105 |
| | 1,041 |
| | 948 |
|
| Income Taxes | 382 |
| | 363 |
| | 377 |
| 576 |
| | 382 |
| | 363 |
|
| Income from Continuing Operations | 659 |
| | 585 |
| | 593 |
| 529 |
| | 659 |
| | 585 |
|
| Income (Loss) from Discontinued Operations, Net of Taxes (Note 1) | — |
| | 51 |
| | (1 | ) | |
| Income from Discontinued Operations, Net of Taxes | | — |
| | — |
| | 51 |
|
| Net Income | 659 |
| | 636 |
| | 592 |
| 529 |
| | 659 |
| | 636 |
|
| Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
| 6 |
| | 6 |
| | 6 |
|
| Net Income (Loss) Attributable to Ameren Common Shareholders: | | | | | | |
| Net Income Attributable to Ameren Common Shareholders: | | | | | | |
| Continuing Operations | 653 |
| | 579 |
| | 587 |
| 523 |
| | 653 |
| | 579 |
|
| Discontinued Operations | — |
| | 51 |
| | (1 | ) | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 653 |
| | $ | 630 |
| | $ | 586 |
| $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | | | | | | |
| Earnings per Common Share – Basic: | | | | | | | | | | |
| Continuing Operations | $ | 2.69 |
| | $ | 2.39 |
| | $ | 2.42 |
| $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.39 |
|
| Discontinued Operations | — |
| | 0.21 |
| | — |
| — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Basic | $ | 2.69 |
| | $ | 2.60 |
| | $ | 2.42 |
| $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.60 |
|
| | | | | | | | | | | |
| Earnings per Common Share – Diluted: | | | | | | | | | | |
| Continuing Operations | $ | 2.68 |
| | $ | 2.38 |
| | $ | 2.40 |
| $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.38 |
|
| Discontinued Operations | — |
| | 0.21 |
| | — |
| — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Diluted | $ | 2.68 |
| | $ | 2.59 |
| | $ | 2.40 |
| $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.59 |
|
| | | | | | | | | | | |
| Dividends per Common Share | $ | 1.715 |
| | $ | 1.655 |
| | $ | 1.610 |
| $ | 1.778 |
| | $ | 1.715 |
| | $ | 1.655 |
|
| Average Common Shares Outstanding – Basic | 242.6 |
| | 242.6 |
| | 242.6 |
| 242.6 |
| | 242.6 |
| | 242.6 |
|
| Average Common Shares Outstanding – Diluted | 243.4 |
| | 243.6 |
| | 244.4 |
| 244.2 |
| | 243.4 |
| | 243.6 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In millions) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In millions) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In millions) |
| | | Year Ended December 31, | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| | | | | | | | | | | |
| Income from Continuing Operations | $ | 659 |
| | $ | 585 |
| | $ | 593 |
| $ | 529 |
| | $ | 659 |
| | $ | 585 |
|
| Other Comprehensive Income from Continuing Operations, Net of Taxes | | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(7), $3, and $(7), respectively | (20 | ) | | 6 |
| | (12 | ) | |
| 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 | 639 |
| | 591 |
| | 581 |
| 534 |
| | 639 |
| | 591 |
|
| Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
| 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 633 |
| | 585 |
| | 575 |
| 528 |
| | 633 |
| | 585 |
|
| | | | | | | |
| Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | 51 |
| | (1 | ) | |
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 633 |
| | $ | 636 |
| | $ | 574 |
| $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) | AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) | AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) |
| | | December 31, | December 31, |
| | 2016 | | 2015 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 9 |
| | $ | 292 |
| $ | 10 |
| | $ | 9 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively) | 437 |
| | 388 |
| 445 |
| | 437 |
|
| Unbilled revenue | 295 |
| | 239 |
| 323 |
| | 295 |
|
| Miscellaneous accounts and notes receivable | 63 |
| | 98 |
| 70 |
| | 63 |
|
| Inventories | 527 |
| | 538 |
| 522 |
| | 527 |
|
| Current regulatory assets | 149 |
| | 260 |
| 144 |
| | 149 |
|
| Other current assets | 98 |
| | 88 |
| 98 |
| | 113 |
|
| Assets of discontinued operations (Note 1) | 15 |
| | 14 |
| |
| Total current assets | 1,593 |
| | 1,917 |
| 1,612 |
| | 1,593 |
|
| Property, Plant, and Equipment, Net | 20,113 |
| | 18,799 |
| 21,466 |
| | 20,113 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 607 |
| | 556 |
| 704 |
| | 607 |
|
| Goodwill | 411 |
| | 411 |
| 411 |
| | 411 |
|
| Regulatory assets | 1,437 |
| | 1,382 |
| 1,230 |
| | 1,437 |
|
| Other assets | 538 |
| | 575 |
| 522 |
| | 538 |
|
| Total investments and other assets | 2,993 |
| | 2,924 |
| 2,867 |
| | 2,993 |
|
| TOTAL ASSETS | $ | 24,699 |
| | $ | 23,640 |
| $ | 25,945 |
| | $ | 24,699 |
|
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 681 |
| | $ | 395 |
| $ | 841 |
| | $ | 681 |
|
| Short-term debt | 558 |
| | 301 |
| 484 |
| | 558 |
|
| Accounts and wages payable | 805 |
| | 777 |
| 902 |
| | 805 |
|
| Taxes accrued | 46 |
| | 43 |
| 52 |
| | 46 |
|
| Interest accrued | 93 |
| | 89 |
| 99 |
| | 93 |
|
| Customer deposits | 107 |
| | 100 |
| 108 |
| | 107 |
|
| Current regulatory liabilities | 110 |
| | 80 |
| 128 |
| | 110 |
|
| Other current liabilities | 248 |
| | 279 |
| 326 |
| | 274 |
|
| Liabilities of discontinued operations (Note 1) | 26 |
| | 29 |
| |
| Total current liabilities | 2,674 |
| | 2,093 |
| 2,940 |
| | 2,674 |
|
| Long-term Debt, Net | 6,595 |
| | 6,880 |
| 7,094 |
| | 6,595 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 4,264 |
| | 3,885 |
| 2,506 |
| | 4,264 |
|
| Accumulated deferred investment tax credits | 55 |
| | 60 |
| 49 |
| | 55 |
|
| Regulatory liabilities | 1,985 |
| | 1,905 |
| 4,387 |
| | 1,985 |
|
| Asset retirement obligations | 635 |
| | 618 |
| 638 |
| | 635 |
|
| Pension and other postretirement benefits | 769 |
| | 580 |
| 545 |
| | 769 |
|
| Other deferred credits and liabilities | 477 |
| | 531 |
| 460 |
| | 477 |
|
| Total deferred credits and other liabilities | 8,185 |
| | 7,579 |
| 8,585 |
| | 8,185 |
|
| Commitments and Contingencies (Notes 2, 10, and 15) |
|
| |
|
| |
| Commitments and Contingencies (Notes 2, 9, and 14) | |
|
| |
|
|
| Ameren Corporation Shareholders’ Equity: | | | | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 | 2 |
| | 2 |
| |
| Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding | | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,556 |
| | 5,616 |
| 5,540 |
| | 5,556 |
|
| Retained earnings | 1,568 |
| | 1,331 |
| 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (23 | ) | | (3 | ) | (18 | ) | | (23 | ) |
| Total Ameren Corporation shareholders’ equity | 7,103 |
| | 6,946 |
| 7,184 |
| | 7,103 |
|
| Noncontrolling Interests | 142 |
| | 142 |
| 142 |
| | 142 |
|
| Total equity | 7,245 |
| | 7,088 |
| 7,326 |
| | 7,245 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 24,699 |
| | $ | 23,640 |
| $ | 25,945 |
| | $ | 24,699 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | Year Ended December 31, | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 659 |
| | $ | 636 |
| | $ | 592 |
| $ | 529 |
| | $ | 659 |
| | $ | 636 |
|
| Loss (Income) from discontinued operations, net of tax | — |
| | (51 | ) | | 1 |
| |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | |
| 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 |
| | — |
| — |
| | — |
| | 69 |
|
| Depreciation and amortization | 835 |
| | 777 |
| | 710 |
| 876 |
| | 835 |
| | 777 |
|
| Amortization of nuclear fuel | 88 |
| | 97 |
| | 81 |
| 76 |
| | 88 |
| | 97 |
|
| Amortization of debt issuance costs and premium/discounts | 22 |
| | 22 |
| | 22 |
| 22 |
| | 22 |
| | 22 |
|
| Deferred income taxes and investment tax credits, net | 386 |
| | 369 |
| | 451 |
| 539 |
| | 386 |
| | 369 |
|
| Allowance for equity funds used during construction | (27 | ) | | (30 | ) | | (34 | ) | (24 | ) | | (27 | ) | | (30 | ) |
| Share-based compensation costs | 17 |
| | 24 |
| | 25 |
| 17 |
| | 17 |
| | 24 |
|
| Other | 4 |
| | (10 | ) | | (24 | ) | (10 | ) | | 4 |
| | (10 | ) |
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | (71 | ) | | 83 |
| | 31 |
| (53 | ) | | (71 | ) | | 83 |
|
| Inventories | 11 |
| | (14 | ) | | 3 |
| 17 |
| | 11 |
| | (14 | ) |
| Accounts and wages payable | 19 |
| | (2 | ) | | 10 |
| 32 |
| | 19 |
| | (2 | ) |
| Taxes accrued | 13 |
| | (22 | ) | | (44 | ) | 55 |
| | 13 |
| | (22 | ) |
| Regulatory assets and liabilities | 215 |
| | 94 |
| | (281 | ) | 36 |
| | 215 |
| | 94 |
|
| Assets, other | (24 | ) | | 53 |
| | 30 |
| 20 |
| | (22 | ) | | 46 |
|
| Liabilities, other | (10 | ) | | (44 | ) | | (14 | ) | (7 | ) | | (9 | ) | | (44 | ) |
| Pension and other postretirement benefits | (16 | ) | | (9 | ) | | (10 | ) | (21 | ) | | (16 | ) | | (9 | ) |
| Counterparty collateral, net | 3 |
| | (7 | ) | | 22 |
| |
| Net cash provided by operating activities – continuing operations | 2,124 |
| | 2,035 |
| | 1,571 |
| 2,104 |
| | 2,124 |
| | 2,035 |
|
| Net cash used in operating activities – discontinued operations | (1 | ) | | (4 | ) | | (6 | ) | — |
| | (1 | ) | | (4 | ) |
| Net cash provided by operating activities | 2,123 |
| | 2,031 |
| | 1,565 |
| 2,104 |
| | 2,123 |
| | 2,031 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (2,076 | ) | | (1,917 | ) | | (1,785 | ) | (2,132 | ) | | (2,076 | ) | | (1,917 | ) |
| Nuclear fuel expenditures | (55 | ) | | (52 | ) | | (74 | ) | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (392 | ) | | (363 | ) | | (405 | ) | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 377 |
| | 349 |
| | 391 |
| 396 |
| | 377 |
| | 349 |
|
| Proceeds from note receivable – Marketing Company | — |
| | 20 |
| | 95 |
| |
| Contributions to note receivable – Marketing Company | — |
| | (8 | ) | | (89 | ) | |
| Other | 5 |
| | 20 |
| | 11 |
| 7 |
| | 5 |
| | 32 |
|
| Net cash used in investing activities – continuing operations | (2,141 | ) | | (1,951 | ) | | (1,856 | ) | (2,205 | ) | | (2,141 | ) | | (1,951 | ) |
| Net cash provided by (used in) investing activities – discontinued operations | — |
| | (25 | ) | | 139 |
| |
| Net cash used in investing activities – discontinued operations | | — |
| | — |
| | (25 | ) |
| Net cash used in investing activities | (2,141 | ) | | (1,976 | ) | | (1,717 | ) | (2,205 | ) | | (2,141 | ) | | (1,976 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Dividends on common stock | (416 | ) | | (402 | ) | | (390 | ) | (431 | ) | | (416 | ) | | (402 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt, net | 257 |
| | (413 | ) | | 346 |
| (74 | ) | | 257 |
| | (413 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (395 | ) | | (120 | ) | | (697 | ) | (681 | ) | | (395 | ) | | (120 | ) |
| Issuances of long-term debt | 389 |
| | 1,197 |
| | 898 |
| 1,345 |
| | 389 |
| | 1,197 |
|
| Capital issuance costs | (9 | ) | | (12 | ) | | (11 | ) | |
| Debt issuance costs | | (11 | ) | | (9 | ) | | (12 | ) |
| Share-based payments | (83 | ) | | (12 | ) | | (14 | ) | (39 | ) | | (83 | ) | | (12 | ) |
| Other | (2 | ) | | — |
| | 1 |
| (1 | ) | | (2 | ) | | — |
|
| Net cash provided by (used in) financing activities – continuing operations | (265 | ) | | 232 |
| | 127 |
| 102 |
| | (265 | ) | | 232 |
|
| Net change in cash and cash equivalents | (283 | ) | | 287 |
| | (25 | ) | 1 |
| | (283 | ) | | 287 |
|
| Cash and cash equivalents at beginning of year | 292 |
| | 5 |
| | 30 |
| 9 |
| | 292 |
| | 5 |
|
| Cash and cash equivalents at end of year | $ | 9 |
| | $ | 292 |
| | $ | 5 |
| $ | 10 |
| | $ | 9 |
| | $ | 292 |
|
| | | | | | | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | | | | | | |
| Interest (net of $15, $17, and $18 capitalized, respectively) | $ | 358 |
| | $ | 335 |
| | $ | 333 |
| |
| Interest (net of $14, $15, and $17 capitalized, respectively) | | $ | 370 |
| | $ | 358 |
| | $ | 335 |
|
| Income taxes, net | (12 | ) | | (15 | ) | | (27 | ) | (19 | ) | | (12 | ) | | (15 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) | AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | December 31, | December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Common Stock: | | | | | | |
| Beginning of year | $ | 2 |
| | $ | 2 |
| | $ | 2 |
| |
| Shares issued | — |
| | — |
| | — |
| |
| Common stock, end of year | 2 |
| | 2 |
| | 2 |
| |
| Common Stock | | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| | | | | | | |
| Other Paid-in Capital: | | | | | | | | | | |
| Beginning of year | 5,616 |
| | 5,617 |
| | 5,632 |
| 5,556 |
| | 5,616 |
| | 5,617 |
|
| Share-based compensation activity | (60 | ) | | (1 | ) | | (15 | ) | (16 | ) | | (60 | ) | | (1 | ) |
| Other paid-in capital, end of year | 5,556 |
| | 5,616 |
| | 5,617 |
| 5,540 |
| | 5,556 |
| | 5,616 |
|
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 1,331 |
| | 1,103 |
| | 907 |
| 1,568 |
| | 1,331 |
| | 1,103 |
|
| Net income attributable to Ameren common shareholders | 653 |
| | 630 |
| | 586 |
| 523 |
| | 653 |
| | 630 |
|
| Dividends | (416 | ) | | (402 | ) | | (390 | ) | (431 | ) | | (416 | ) | | (402 | ) |
| Retained earnings, end of year | 1,568 |
| | 1,331 |
| | 1,103 |
| 1,660 |
| | 1,568 |
| | 1,331 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | | | | | | |
| Deferred retirement benefit costs, beginning of year | (3 | ) | | (9 | ) | | 3 |
| (23 | ) | | (3 | ) | | (9 | ) |
| Change in deferred retirement benefit costs | (20 | ) | | 6 |
| | (12 | ) | 5 |
| | (20 | ) | | 6 |
|
| Deferred retirement benefit costs, end of year | (23 | ) | | (3 | ) | | (9 | ) | (18 | ) | | (23 | ) | | (3 | ) |
| Total accumulated other comprehensive loss, end of year | (23 | ) | | (3 | ) | | (9 | ) | (18 | ) | | (23 | ) | | (3 | ) |
| Total Ameren Corporation Shareholders’ Equity | $ | 7,103 |
| | $ | 6,946 |
| | $ | 6,713 |
| $ | 7,184 |
| | $ | 7,103 |
| | $ | 6,946 |
|
| | | | | | | | | | | |
| Noncontrolling Interests: | | | | | | | | | | |
| Beginning of year | 142 |
| | 142 |
| | 142 |
| 142 |
| | 142 |
| | 142 |
|
| Net income attributable to noncontrolling interest holders | 6 |
| | 6 |
| | 6 |
| 6 |
| | 6 |
| | 6 |
|
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) | (6 | ) | | (6 | ) | | (6 | ) |
| Noncontrolling interests, end of year | 142 |
| | 142 |
| | 142 |
| 142 |
| | 142 |
| | 142 |
|
| Total Equity | $ | 7,245 |
| | $ | 7,088 |
| | $ | 6,855 |
| $ | 7,326 |
| | $ | 7,245 |
| | $ | 7,088 |
|
| | | | | | | | | | | |
| | | | | | | |
| Common stock shares at end of year | 242.6 |
| | 242.6 |
| | 242.6 |
| 242.6 |
| | 242.6 |
| | 242.6 |
|
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) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions) | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions) |
| | | Year Ended December 31, | Year Ended December 31, |
| | 2016 |
| 2015 | | 2014 | 2017 |
| 2016 | | 2015 |
| Operating Revenues: |
|
|
| | |
|
|
| | |
| Electric | $ | 3,394 |
|
| $ | 3,470 |
| | $ | 3,388 |
| $ | 3,413 |
|
| $ | 3,394 |
| | $ | 3,470 |
|
| Natural gas | 128 |
|
| 137 |
| | 164 |
| 126 |
|
| 128 |
| | 137 |
|
| Other | 1 |
|
| 2 |
| | 1 |
| — |
|
| 1 |
| | 2 |
|
| Total operating revenues | 3,523 |
|
| 3,609 |
| | 3,553 |
| 3,539 |
|
| 3,523 |
| | 3,609 |
|
| Operating Expenses: |
|
|
| | |
|
|
| | |
| Fuel | 745 |
|
| 878 |
| | 826 |
| 737 |
|
| 745 |
| | 878 |
|
| Purchased power | 252 |
|
| 111 |
| | 126 |
| 245 |
|
| 252 |
| | 111 |
|
| Natural gas purchased for resale | 49 |
| | 57 |
| | 82 |
| 47 |
| | 49 |
| | 57 |
|
| Other operations and maintenance | 893 |
| | 925 |
| | 939 |
| 902 |
| | 893 |
| | 925 |
|
| Provision for Callaway construction and operating license (Note 2) | — |
| | 69 |
| | — |
| |
| Provision for Callaway construction and operating license | | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 514 |
| | 492 |
| | 473 |
| 533 |
| | 514 |
| | 492 |
|
| Taxes other than income taxes | 325 |
| | 335 |
| | 322 |
| 328 |
| | 325 |
| | 335 |
|
| Total operating expenses | 2,778 |
| | 2,867 |
| | 2,768 |
| 2,792 |
| | 2,778 |
| | 2,867 |
|
| Operating Income | 745 |
| | 742 |
| | 785 |
| 747 |
| | 745 |
| | 742 |
|
| Other Income and Expenses: | | | | | | | | | | |
| Miscellaneous income | 52 |
| | 52 |
| | 60 |
| 48 |
| | 52 |
| | 52 |
|
| Miscellaneous expense | 10 |
| | 11 |
| | 12 |
| 8 |
| | 10 |
| | 11 |
|
| Total other income | 42 |
| | 41 |
| | 48 |
| 40 |
| | 42 |
| | 41 |
|
| Interest Charges | 211 |
| | 219 |
| | 211 |
| 207 |
| | 211 |
| | 219 |
|
| Income Before Income Taxes | 576 |
| | 564 |
| | 622 |
| 580 |
| | 576 |
| | 564 |
|
| Income Taxes | 216 |
| | 209 |
| | 229 |
| 254 |
| | 216 |
| | 209 |
|
| Net Income | 360 |
| | 355 |
| | 393 |
| 326 |
| | 360 |
| | 355 |
|
| Other Comprehensive Income | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Comprehensive Income | $ | 360 |
| | $ | 355 |
| | $ | 393 |
| $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
| Net Income | $ | 360 |
| | $ | 355 |
| | $ | 393 |
| $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
| 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 357 |
| | $ | 352 |
| | $ | 390 |
| $ | 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, |
| | 2016 | | 2015 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 199 |
| $ | — |
| | $ | — |
|
| Advances to money pool | 161 |
| | 36 |
| — |
| | 161 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively) | 187 |
| | 174 |
| 200 |
| | 187 |
|
| Accounts receivable – affiliates | 12 |
| | 54 |
| 11 |
| | 12 |
|
| Unbilled revenue | 154 |
| | 128 |
| 165 |
| | 154 |
|
| Miscellaneous accounts and notes receivable | 14 |
| | 78 |
| 35 |
| | 14 |
|
| Inventories | 392 |
| | 387 |
| 388 |
| | 392 |
|
| Current regulatory assets | 35 |
| | 89 |
| 56 |
| | 35 |
|
| Other current assets | 49 |
| | 41 |
| 50 |
| | 49 |
|
| Total current assets | 1,004 |
| | 1,186 |
| 905 |
| | 1,004 |
|
| Property, Plant, and Equipment, Net | 11,478 |
| | 11,183 |
| 11,751 |
| | 11,478 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 607 |
| | 556 |
| 704 |
| | 607 |
|
| Regulatory assets | 619 |
| | 605 |
| 395 |
| | 619 |
|
| Other assets | 327 |
| | 321 |
| 288 |
| | 327 |
|
| Total investments and other assets | 1,553 |
| | 1,482 |
| 1,387 |
| | 1,553 |
|
| TOTAL ASSETS | $ | 14,035 |
| | $ | 13,851 |
| $ | 14,043 |
| | $ | 14,035 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 431 |
| | $ | 266 |
| $ | 384 |
| | $ | 431 |
|
| Short-term debt | | 39 |
| | — |
|
| Accounts and wages payable | 444 |
| | 417 |
| 475 |
| | 444 |
|
| Accounts payable – affiliates | 68 |
| | 56 |
| 60 |
| | 68 |
|
| Taxes accrued | 30 |
| | 31 |
| 30 |
| | 30 |
|
| Interest accrued | 54 |
| | 59 |
| 54 |
| | 54 |
|
| Current regulatory liabilities | 12 |
| | 28 |
| 19 |
| | 12 |
|
| Other current liabilities | 123 |
| | 120 |
| 103 |
| | 123 |
|
| Total current liabilities | 1,162 |
| | 977 |
| 1,164 |
| | 1,162 |
|
| Long-term Debt, Net | 3,563 |
| | 3,844 |
| 3,577 |
| | 3,563 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 3,013 |
| | 2,844 |
| 1,650 |
| | 3,013 |
|
| Accumulated deferred investment tax credits | 53 |
| | 58 |
| 48 |
| | 53 |
|
| Regulatory liabilities | 1,215 |
| | 1,172 |
| 2,664 |
| | 1,215 |
|
| Asset retirement obligations | 629 |
| | 612 |
| 634 |
| | 629 |
|
| Pension and other postretirement benefits | 291 |
| | 234 |
| 213 |
| | 291 |
|
| Other deferred credits and liabilities | 19 |
| | 28 |
| 12 |
| | 19 |
|
| Total deferred credits and other liabilities | 5,220 |
| | 4,948 |
| 5,221 |
| | 5,220 |
|
| Commitments and Contingencies (Notes 2, 10, 14, and 15) |
| |
| |
| 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 | 1,828 |
| | 1,822 |
| 1,858 |
| | 1,828 |
|
| Preferred stock | 80 |
| | 80 |
| 80 |
| | 80 |
|
| Retained earnings | 1,671 |
| | 1,669 |
| 1,632 |
| | 1,671 |
|
| Total shareholders’ equity | 4,090 |
| | 4,082 |
| 4,081 |
| | 4,090 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 14,035 |
| | $ | 13,851 |
| $ | 14,043 |
| | $ | 14,035 |
|
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, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 360 |
| | $ | 355 |
| | $ | 393 |
| $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
| Provision for Callaway construction and operating license | — |
| | 69 |
| | — |
| — |
| | — |
| | 69 |
|
| Depreciation and amortization | 506 |
| | 476 |
| | 442 |
| 514 |
| | 506 |
| | 476 |
|
| Amortization of nuclear fuel | 88 |
| | 97 |
| | 81 |
| 76 |
| | 88 |
| | 97 |
|
| Amortization of debt issuance costs and premium/discounts | 6 |
| | 6 |
| | 7 |
| 6 |
| | 6 |
| | 6 |
|
| Deferred income taxes and investment tax credits, net | 179 |
| | 82 |
| | 245 |
| 82 |
| | 179 |
| | 82 |
|
| Allowance for equity funds used during construction | (23 | ) | | (22 | ) | | (32 | ) | (21 | ) | | (23 | ) | | (22 | ) |
| Other | 5 |
| | 2 |
| | 3 |
| 4 |
| | 5 |
| | 2 |
|
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | 5 |
| | 72 |
| | (10 | ) | (46 | ) | | 5 |
| | 72 |
|
| Inventories | (4 | ) | | (39 | ) | | 8 |
| 18 |
| | (4 | ) | | (39 | ) |
| Accounts and wages payable | (18 | ) | | 3 |
| | 25 |
| 27 |
| | (18 | ) | | 3 |
|
| Taxes accrued | 11 |
| | 1 |
| | (197 | ) | (1 | ) | | 11 |
| | 1 |
|
| Regulatory assets and liabilities | 84 |
| | 117 |
| | (68 | ) | 26 |
| | 84 |
| | 117 |
|
| Assets, other | (25 | ) | | 26 |
| | 52 |
| 30 |
| | (25 | ) | | 26 |
|
| Liabilities, other | (1 | ) | | 4 |
| | — |
| (23 | ) | | (1 | ) | | 4 |
|
| Pension and other postretirement benefits | (4 | ) | | (2 | ) | | 1 |
| (2 | ) | | (4 | ) | | (2 | ) |
| Net cash provided by operating activities | 1,169 |
| | 1,247 |
| | 950 |
| 1,016 |
| | 1,169 |
| | 1,247 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (738 | ) | | (622 | ) | | (747 | ) | (773 | ) | | (738 | ) | | (622 | ) |
| Nuclear fuel expenditures | (55 | ) | | (52 | ) | | (74 | ) | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (392 | ) | | (363 | ) | | (405 | ) | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 377 |
| | 349 |
| | 391 |
| 396 |
| | 377 |
| | 349 |
|
| Money pool advances, net | (125 | ) | | (36 | ) | | — |
| 161 |
| | (125 | ) | | (36 | ) |
| Other | (1 | ) | | — |
| | (2 | ) | 7 |
| | (1 | ) | | — |
|
| Net cash used in investing activities | (934 | ) | | (724 | ) | | (837 | ) | (685 | ) | | (934 | ) | | (724 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Dividends on common stock | (355 | ) | | (575 | ) | | (340 | ) | (362 | ) | | (355 | ) | | (575 | ) |
| Return of capital to parent | — |
| | — |
| | (215 | ) | |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | — |
| | (97 | ) | | 97 |
| 39 |
| | — |
| | (97 | ) |
| Money pool borrowings, net | — |
| | — |
| | (105 | ) | |
| Redemptions, repurchases, and maturities of long-term debt | (266 | ) | | (120 | ) | | (109 | ) | (431 | ) | | (266 | ) | | (120 | ) |
| Issuances of long-term debt | 149 |
| | 249 |
| | 350 |
| 399 |
| | 149 |
| | 249 |
|
| Capital issuance costs | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Capital contribution from parent | 44 |
| | 224 |
| | 215 |
| 30 |
| | 44 |
| | 224 |
|
| Net cash used in financing activities | (434 | ) | | (325 | ) | | (113 | ) | (331 | ) | | (434 | ) | | (325 | ) |
| Net change in cash and cash equivalents | (199 | ) | | 198 |
| | — |
| — |
| | (199 | ) | | 198 |
|
| Cash and cash equivalents at beginning of year | 199 |
| | 1 |
| | 1 |
| — |
| | 199 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | — |
| | $ | 199 |
| | $ | 1 |
| $ | — |
| | $ | — |
| | $ | 199 |
|
| | | | | | | | | | | |
Noncash financing activity – capital contribution from parent | $ | — |
| | $ | 38 |
| | $ | 9 |
| $ | — |
| | $ | — |
| | $ | 38 |
|
| | | | | | | | | | | |
| Cash Paid During the Year: | | | | | | | | | | |
| Interest (net of $12, $12, and $16 capitalized, respectively) | $ | 209 |
| | $ | 212 |
| | $ | 203 |
| |
| Interest (net of $10, $12, and $12 capitalized, respectively) | | $ | 202 |
| | $ | 209 |
| | $ | 212 |
|
| Income taxes, net | 27 |
| | 72 |
| | 215 |
| 178 |
| | 27 |
| | 72 |
|
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, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
| $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| | | | | | | | | | | |
| Other Paid-in Capital: | | | | | | | | | | |
| Beginning of year | 1,822 |
| | 1,569 |
| | 1,560 |
| 1,828 |
| | 1,822 |
| | 1,569 |
|
| Capital contribution from parent (Note 1) | 6 |
| | 253 |
| | 224 |
| |
| Return of capital to parent (Note 1) | — |
| | — |
| | (215 | ) | |
| Capital contribution from parent | | 30 |
| | 6 |
| | 253 |
|
| Other paid-in capital, end of year | 1,828 |
| | 1,822 |
| | 1,569 |
| 1,858 |
| | 1,828 |
| | 1,822 |
|
| | | | | | | | | | | |
| Preferred Stock | 80 |
| | 80 |
| | 80 |
| 80 |
| | 80 |
| | 80 |
|
| | | | | | | | | | | |
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 1,669 |
| | 1,892 |
| | 1,842 |
| 1,671 |
| | 1,669 |
| | 1,892 |
|
| Net income | 360 |
| | 355 |
| | 393 |
| 326 |
| | 360 |
| | 355 |
|
| Common stock dividends | (355 | ) | | (575 | ) | | (340 | ) | (362 | ) | | (355 | ) | | (575 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,671 |
| | 1,669 |
| | 1,892 |
| 1,632 |
| | 1,671 |
| | 1,669 |
|
| | | | | | | | | | | |
| Total Shareholders’ Equity | $ | 4,090 |
| | $ | 4,082 |
| | $ | 4,052 |
| $ | 4,081 |
| | $ | 4,090 |
| | $ | 4,082 |
|
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, | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Operating Revenues: | | | | | | | | | | |
| Electric | $ | 1,736 |
| | $ | 1,683 |
| | $ | 1,522 |
| $ | 1,784 |
| | $ | 1,736 |
| | $ | 1,683 |
|
| Natural gas | 754 |
| | 783 |
| | 976 |
| 743 |
| | 754 |
| | 783 |
|
| Other | | 1 |
| | — |
| | — |
|
| Total operating revenues | 2,490 |
| | 2,466 |
| | 2,498 |
| 2,528 |
| | 2,490 |
| | 2,466 |
|
| Operating Expenses: | | | | | | | | | | |
| Purchased power | 399 |
| | 420 |
| | 343 |
| 417 |
| | 399 |
| | 420 |
|
| Natural gas purchased for resale | 292 |
| | 358 |
| | 533 |
| 264 |
| | 292 |
| | 358 |
|
| Other operations and maintenance | 804 |
| | 797 |
| | 771 |
| 789 |
| | 804 |
| | 797 |
|
| Depreciation and amortization | 319 |
| | 295 |
| | 263 |
| 341 |
| | 319 |
| | 295 |
|
| Taxes other than income taxes | 132 |
| | 130 |
| | 138 |
| 137 |
| | 132 |
| | 130 |
|
| Total operating expenses | 1,946 |
| | 2,000 |
| | 2,048 |
| 1,948 |
| | 1,946 |
| | 2,000 |
|
| Operating Income | 544 |
| | 466 |
| | 450 |
| 580 |
| | 544 |
| | 466 |
|
| Other Income and Expenses: | | | | | | | | | | |
| Miscellaneous income | 21 |
| | 21 |
| | 17 |
| 11 |
| | 21 |
| | 21 |
|
| Miscellaneous expense | 12 |
| | 12 |
| | 8 |
| 10 |
| | 12 |
| | 12 |
|
| Total other income | 9 |
| | 9 |
| | 9 |
| 1 |
| | 9 |
| | 9 |
|
| Interest Charges | 140 |
| | 131 |
| | 112 |
| 144 |
| | 140 |
| | 131 |
|
| Income Before Income Taxes | 413 |
| | 344 |
| | 347 |
| 437 |
| | 413 |
| | 344 |
|
| Income Taxes | 158 |
| | 127 |
| | 143 |
| 166 |
| | 158 |
| | 127 |
|
| Net Income | 255 |
| | 217 |
| | 204 |
| 271 |
| | 255 |
| | 217 |
|
| Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $(1), $(2), and $(2), respectively | (5 | ) | | (3 | ) | | (3 | ) | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $-, $(1), and $(2), respectively | | — |
| | (5 | ) | | (3 | ) |
| Comprehensive Income | $ | 250 |
| | $ | 214 |
| | $ | 201 |
| $ | 271 |
| | $ | 250 |
| | $ | 214 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
| Net Income | $ | 255 |
| | $ | 217 |
| | $ | 204 |
| $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
| 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 252 |
| | $ | 214 |
| | $ | 201 |
| $ | 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, |
| | 2016 | | 2015 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 71 |
| $ | — |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively) | 242 |
| | 204 |
| 234 |
| | 242 |
|
| Accounts receivable – affiliates | 10 |
| | 22 |
| 9 |
| | 10 |
|
| Unbilled revenue | 141 |
| | 111 |
| 158 |
| | 141 |
|
| Miscellaneous accounts receivable | 22 |
| | 19 |
| 35 |
| | 22 |
|
| Inventories | 135 |
| | 151 |
| 134 |
| | 135 |
|
| Current regulatory assets | 108 |
| | 167 |
| 87 |
| | 108 |
|
| Other current assets | 25 |
| | 15 |
| 15 |
| | 25 |
|
| Total current assets | 683 |
| | 760 |
| 672 |
| | 683 |
|
| Property, Plant, and Equipment, Net | 7,469 |
| | 6,848 |
| 8,293 |
| | 7,469 |
|
| Investments and Other Assets: | | | | | | |
| Goodwill | 411 |
| | 411 |
| 411 |
| | 411 |
|
| Regulatory assets | 816 |
| | 771 |
| 822 |
| | 816 |
|
| Other assets | 95 |
| | 113 |
| 147 |
| | 95 |
|
| Total investments and other assets | 1,322 |
| | 1,295 |
| 1,380 |
| | 1,322 |
|
| TOTAL ASSETS | $ | 9,474 |
| | $ | 8,903 |
| $ | 10,345 |
| | $ | 9,474 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 250 |
| | $ | 129 |
| $ | 457 |
| | $ | 250 |
|
| Short-term debt | 51 |
| | — |
| 62 |
| | 51 |
|
| Accounts and wages payable | 264 |
| | 249 |
| 337 |
| | 264 |
|
| Accounts payable – affiliates | 63 |
| | 66 |
| 70 |
| | 63 |
|
| Taxes accrued | 16 |
| | 13 |
| 19 |
| | 16 |
|
| Interest accrued | 33 |
| | 28 |
| 33 |
| | 33 |
|
| Customer deposits | 69 |
| | 69 |
| 69 |
| | 69 |
|
| Mark-to-market derivative liabilities | 15 |
| | 45 |
| |
| Current environmental remediation | 38 |
| | 28 |
| 42 |
| | 38 |
|
| Current regulatory liabilities | 78 |
| | 39 |
| 92 |
| | 78 |
|
| Other current liabilities | 94 |
| | 86 |
| 177 |
| | 109 |
|
| Total current liabilities | 971 |
| | 752 |
| 1,358 |
| | 971 |
|
| Long-term Debt, Net | 2,338 |
| | 2,342 |
| 2,373 |
| | 2,338 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 1,631 |
| | 1,480 |
| 1,021 |
| | 1,631 |
|
| Accumulated deferred investment tax credits | 2 |
| | 2 |
| 1 |
| | 2 |
|
| Regulatory liabilities | 768 |
| | 732 |
| 1,629 |
| | 768 |
|
| Pension and other postretirement benefits | 346 |
| | 271 |
| 285 |
| | 346 |
|
| Environmental remediation | 162 |
| | 205 |
| 134 |
| | 162 |
|
| Other deferred credits and liabilities | 222 |
| | 222 |
| 234 |
| | 222 |
|
| Total deferred credits and other liabilities | 3,131 |
| | 2,912 |
| 3,304 |
| | 3,131 |
|
| Commitments and Contingencies (Notes 2, 14, and 15) |
|
| |
|
| |
| 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 | 2,005 |
| | 2,005 |
| 2,013 |
| | 2,005 |
|
| Preferred stock | 62 |
| | 62 |
| 62 |
| | 62 |
|
| Retained earnings | 967 |
| | 825 |
| 1,235 |
| | 967 |
|
| Accumulated other comprehensive income | — |
| | 5 |
| |
| Total shareholders’ equity | 3,034 |
| | 2,897 |
| 3,310 |
| | 3,034 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 9,474 |
| | $ | 8,903 |
| $ | 10,345 |
| | $ | 9,474 |
|
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) | AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) | AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) |
| | | Year Ended December 31, | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 255 |
| | $ | 217 |
| | $ | 204 |
| $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | 318 |
| | 292 |
| | 259 |
| 341 |
| | 318 |
| | 292 |
|
| Amortization of debt issuance costs and premium/discounts | 14 |
| | 14 |
| | 13 |
| 13 |
| | 14 |
| | 14 |
|
| Deferred income taxes and investment tax credits, net | 154 |
| | 221 |
| | 196 |
| 171 |
| | 154 |
| | 221 |
|
| Other | (1 | ) | | (14 | ) | | (19 | ) | — |
| | (1 | ) | | (14 | ) |
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | (72 | ) | | 16 |
| | (13 | ) | (7 | ) | | (72 | ) | | 16 |
|
| Inventories | 15 |
| | 25 |
| | (4 | ) | (1 | ) | | 15 |
| | 25 |
|
| Accounts and wages payable | 12 |
| | 37 |
| | 7 |
| 19 |
| | 12 |
| | 37 |
|
| Taxes accrued | 1 |
| | (2 | ) | | (7 | ) | 18 |
| | 1 |
| | (2 | ) |
| Regulatory assets and liabilities | 120 |
| | (26 | ) | | (215 | ) | 16 |
| | 120 |
| | (26 | ) |
| Assets, other | (3 | ) | | 17 |
| | 15 |
| (15 | ) | | (3 | ) | | 17 |
|
| Liabilities, other | (5 | ) | | (27 | ) | | 1 |
| 3 |
| | (5 | ) | | (27 | ) |
| Pension and other postretirement benefits | (8 | ) | | (4 | ) | | (6 | ) | (14 | ) | | (8 | ) | | (4 | ) |
| Counterparty collateral, net | 3 |
| | (3 | ) | | 14 |
| — |
| | 3 |
| | (3 | ) |
| Net cash provided by operating activities | 803 |
| | 763 |
| | 445 |
| 815 |
| | 803 |
| | 763 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (924 | ) | | (918 | ) | | (835 | ) | (1,076 | ) | | (924 | ) | | (918 | ) |
| Other | 6 |
| | 5 |
| | 7 |
| 6 |
| | 6 |
| | 5 |
|
| Net cash used in investing activities | (918 | ) | | (913 | ) | | (828 | ) | (1,070 | ) | | (918 | ) | | (913 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Dividends on common stock | (110 | ) | | — |
| | — |
| — |
| | (110 | ) | | — |
|
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 51 |
| | (32 | ) | | 32 |
| 11 |
| | 51 |
| | (32 | ) |
| Money pool borrowings, net | — |
| | (15 | ) | | (41 | ) | — |
| | — |
| | (15 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (129 | ) | | — |
| | (163 | ) | (250 | ) | | (129 | ) | | — |
|
| Issuances of long-term debt | 240 |
| | 248 |
| | 548 |
| 496 |
| | 240 |
| | 248 |
|
| Capital issuance costs | (4 | ) | | (3 | ) | | (6 | ) | (6 | ) | | (4 | ) | | (3 | ) |
| Capital contribution from parent | — |
| | 25 |
| | 15 |
| 8 |
| | — |
| | 25 |
|
| Other | (1 | ) | | — |
| | 1 |
| (1 | ) | | (1 | ) | | — |
|
| Net cash provided by financing activities | 44 |
| | 220 |
| | 383 |
| 255 |
| | 44 |
| | 220 |
|
| Net change in cash and cash equivalents | (71 | ) | | 70 |
| | — |
| — |
| | (71 | ) | | 70 |
|
| Cash and cash equivalents at beginning of year | 71 |
| | 1 |
| | 1 |
| — |
| | 71 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | — |
| | $ | 71 |
| | $ | 1 |
| $ | — |
| | $ | — |
| | $ | 71 |
|
| | | | | | | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | | | | | | |
| Interest (net of $3, $5, and $2 capitalized, respectively) | $ | 127 |
| | $ | 120 |
| | $ | 110 |
| |
| Interest (net of $4, $3, and $5 capitalized, respectively) | | $ | 139 |
| | $ | 127 |
| | $ | 120 |
|
| Income taxes, net | 8 |
| | (113 | ) | | (44 | ) | (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) | AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) | AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | December 31, | December 31, |
| | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | |
| Other Paid-in Capital |
| |
| |
|
| |
| |
|
| Beginning of year | 2,005 |
| | 1,980 |
| | 1,965 |
| 2,005 |
| | 2,005 |
| | 1,980 |
|
| Capital contribution from parent (Note 1) | — |
| | 25 |
| | 15 |
| |
| Capital contribution from parent | | 8 |
| | — |
| | 25 |
|
| Other paid-in capital, end of year | 2,005 |
| | 2,005 |
| | 1,980 |
| 2,013 |
| | 2,005 |
| | 2,005 |
|
| | | | | | | | | | | |
| Preferred Stock | 62 |
| | 62 |
| | 62 |
| 62 |
| | 62 |
| | 62 |
|
| | | | | | | | | | | |
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 825 |
| | 611 |
| | 410 |
| 967 |
| | 825 |
| | 611 |
|
| Net income | 255 |
| | 217 |
| | 204 |
| 271 |
| | 255 |
| | 217 |
|
| Common stock dividends | (110 | ) | | — |
| | — |
| — |
| | (110 | ) | | — |
|
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 967 |
| | 825 |
| | 611 |
| 1,235 |
| | 967 |
| | 825 |
|
| | | | | | | | | | | |
| Accumulated Other Comprehensive Income: | | | | | | | | | | |
| Deferred retirement benefit costs, beginning of year | 5 |
| | 8 |
| | 11 |
| — |
| | 5 |
| | 8 |
|
| Change in deferred retirement benefit costs | (5 | ) | | (3 | ) | | (3 | ) | — |
| | (5 | ) | | (3 | ) |
| Deferred retirement benefit costs, end of year | — |
| | 5 |
| | 8 |
| — |
| | — |
| | 5 |
|
| Total accumulated other comprehensive income, end of year | — |
| | 5 |
| | 8 |
| — |
| | — |
| | 5 |
|
| | | | | | | | | | | |
| Total Shareholders’ Equity | $ | 3,034 |
| | $ | 2,897 |
| | $ | 2,661 |
| $ | 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 DecemberDECEMBER 31, 20162017
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. Ameren’swhose primary assets are its equity interests in its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. 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.below, including Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has various other subsidiaries that conduct other activities, such as the provision of 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-mile24,000-square-mile area in central and eastern Missouri. This area has an estimated population of 2.8 million andMissouri, 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 portions ofa 40,000 square mile area in central and southern Illinois with an estimated population of 3.1 million in an area of 40,000 square miles.Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 0.8 million customers.
ATXI operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers Spoon River, and Mark Twain projects. ATXI is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.projects, and placed the Spoon River project in service in February 2018.
Ameren'sAmeren’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. 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
We 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 cost recoveryrate-adjustment mechanisms discussed in the Purchased Gas, Power, and Fuel Rate-adjustment Mechanisms section below,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 efficiencyenergy-efficiency rider. Ameren Illinois'Illinois’ and ATXI'sATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois' electric distribution businessIllinois participates in the performance-based formula ratemaking processframeworks established pursuant to the IEIMA.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, an energy efficiencynatural 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 the regulatory assets and liabilities.
liabilities recorded at December 31, 2017 and 2016.
The Ameren Illinois asbestos-related litigation rider includes a trust fund that was established when Ameren acquired IP.fund. At December 31, 20162017 and 2015,2016, the trust fund balance of $23 million and $22 million, respectively, was reflected in "Other assets"“Other assets” on Ameren'sAmeren’s and Ameren Illinois'Illinois’ balance sheet.sheets. This balance 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 to be recovered from the trust fund. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of
three months or less.
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 market. Cost is determined by the average-cost method.net realizable value. Inventories are capitalized when purchased and then expensed as consumed or capitalized as property, plant, assetsand equipment when installed, as appropriate. The following table presents a breakdown of inventories for each of the Ameren Companies at December 31, 20162017 and 20152016:
| | | | | Ameren Missouri | | Ameren Illinois | | Ameren | | 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 |
| | $ | 172 |
| | $ | — |
| | $ | 172 |
|
| Natural gas stored underground | | 9 |
| | 73 |
| | 82 |
| | 9 |
| | 73 |
| | 82 |
|
| Other inventories | | 211 |
| | 62 |
| | 273 |
| |
| Materials, supplies, and other | | | 211 |
| | 62 |
| | 273 |
|
| Total inventories | | $ | 392 |
| | $ | 135 |
| | $ | 527 |
| | $ | 392 |
| | $ | 135 |
| | $ | 527 |
|
| 2015 | | | | | | | |
Fuel(a) | | $ | 173 |
| | $ | — |
| | $ | 173 |
| |
| Natural gas stored underground | | 10 |
| | 87 |
| | 97 |
| |
| Other inventories | | 204 |
| | 64 |
| | 268 |
| |
| Total inventories | | $ | 387 |
| | $ | 151 |
| | $ | 538 |
| |
| |
| (a) | Consists of coal, oil, and propane. |
Purchased Gas, Power and Fuel Rate-adjustment Mechanisms
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 rate case proceeding. See Note 2 – Rate and Regulatory Matters for the regulatory assets and liabilities recorded at December 31, 2016 and 2015, related to the rate-adjustment mechanisms discussed below.
In Ameren Missouri’s and Ameren Illinois’ natural gas businesses, changes in natural gas costs are reflected in billings to their 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.
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.
Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, including transportation charges and revenues, net of off-system
sales, greater or less than 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. Since May 30, 2015, transmission revenues and substantially all transmission charges are excluded from net energy costs as a result of the April 2015 MoPSC electric rate order.
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, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less 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.
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 provision for depreciation for the Ameren Companies in
2017, 2016, 2015, and 20142015 ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
We capitalize allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common shareholders’ equity) applicable to rate-regulated construction expenditures, in accordance with the utility industry'sindustry’s accounting practice. 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,, 2015, and 2014:2015:
| | | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Ameren Missouri | 7 | % | | 7 | % | | 7 | % | 7 | % | | 7 | % | | 7 | % |
| Ameren Illinois | 5 | % | | 6 | % | | 2 | % | 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, 2017 and 2016. Ameren has four reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois has three 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, 2017 and 2016. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 2017 and 2016.
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 and circumstances change that would more likely than not reduce the fair value of their reporting units below their carrying amounts. Ameren and Ameren Illinois had goodwill of $411 million at October 31, 2016 and October 31, 2015. 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 two-step quantitative test, on an annual basis. On OctoberDecember 31, 2015,2016, due to a change in reporting units, Ameren and Ameren Illinois performed a quantitative test and determined that the estimated fair value of the Ameren Illinoiseach reporting unit significantly exceeded its respective carrying value as of that date. Based on these results, Ameren and Ameren Illinois elected to perform a qualitative assessment for their annual goodwill impairment test conducted as of October 31, 2016.2017.
The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was more likely than not that the fair value of the Ameren Illinoiseach reporting unit significantly exceeded its carrying value as of October 31, 2016,2017, resulting in no impairment of Ameren’s or Ameren Illinois’ goodwill. The following factors, among others, were considered by Ameren and Ameren Illinois when assessingthey assessed whether it was more likely than not that the fair value of the Ameren Illinoiseach of their reporting unitunits exceeded its carrying value for theas of October 31, 2016, test:2017:
macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
pending regulatory rate casereview outcomes and projections of future regulatory rate casereview 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 relatedwith respect to transmission services; and
projected operating results and cash flows.
As of December 31, 2016, the Ameren Companies changed the manner in which they assess performance and allocate resources, driven by increasing investment in FERC rate-regulated electric transmission and Ameren Illinois electric distribution and natural gas distribution businesses as well as the unique regulatory environment for each jurisdiction. Ameren now has four reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois now has three reporting units: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 16 – Segment Information for additional information related to the change in Ameren’s and Ameren Illinois' segments.
As of the date of the segment change, December 31, 2016, Ameren and Ameren Illinois reassigned goodwill to the new reporting units using a relative fair value allocation approach. The Level 3 fair value hierarchy valuation approach used to reassign goodwill was based on a market participant view and used a weighted combination of a discounted cash flow analysis and a market multiples analysis. Key assumptions used in estimating the fair value of the reporting units included discount and growth rates, utility sector market performance and transactions, and projected operating results and cash flows. As a result of the goodwill reassignment, 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, 2016. The Ameren Transmission reporting unit was reassigned the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit.
In conjunction with the goodwill reassignment, Ameren and Ameren Illinois completed the first step of the quantitative test to determine whether the fair values of the new reporting units exceeded their carrying values as of December 31, 2016. Ameren and Ameren Illinois determined that the estimated fair values of the Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, Ameren Illinois Transmission, and Ameren Transmission reporting units each exceeded their respective carrying values by at least 40%, indicating no impairment of Ameren’s or Ameren Illinois’ goodwill. The Ameren and Ameren Illinois goodwill that was reassigned to the new reporting units on December 31, 2016, had no accumulated goodwill impairment losses.
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 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 20162017 and 2015.2016.
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.
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 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,“Property, Plant, and Equipment, Net"Net” on the balance sheet, are depreciated over the remaining useful life of the related asset. Due to regulatory recovery, that depreciation is recorded withindeferred as a regulatory balance. The depreciation of the asset or liability balance relatedbook values at Ameren Missouri was $26 million, $31 million, and $13 million for the years ended December 31, 2017, 2016, and 2015, respectively, which was deferred as a reduction to AROs.the net regulatory liability. 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 and are currently recorded as a regulatory liability, along with the depreciation of the asset book values, discussed above, and the accretion of the AROs. The depreciation of the asset book values at Ameren Missouri was $31 million, $13 million, and $1 million for the years ended December 31, 2016, 2015, and 2014, respectively, which was recorded as a reduction to the regulatory liability. The depreciation recorded to the regulatory asset at Ameren Illinois was immaterial in each respective period. 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 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 2 – Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years ended December 31, 20162017 and 2015:2016:
| | | | Ameren Missouri | | Ameren Illinois | | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren | |
| Balance at December 31, 2014 | $ | 389 |
| | $ | 7 |
| | $ | 396 |
| | |
| Liabilities incurred | 3 |
| | — |
| | 3 |
| | |
| Liabilities settled | (1 | ) | | (1 | ) | | (2 | ) | | |
Accretion in 2015(a) | 23 |
| | (b) |
| | 23 |
| | |
Change in estimates(c) | 203 |
| | (b) |
| | 203 |
| | |
| Balance at December 31, 2015 | $ | 617 |
| (e) | $ | 6 |
| (d) | $ | 623 |
| (e) | $ | 617 |
| | $ | 6 |
| | $ | 623 |
| |
| Liabilities incurred | 3 |
| | — |
| | 3 |
| | 3 |
| | — |
| | 3 |
| |
| Liabilities settled | (2 | ) | | (b) |
| | (2 | ) | | (2 | ) | | (a) |
| | (2 | ) | |
Accretion in 2016(a) | 25 |
| | (b) |
| | 25 |
| | |
Accretion in 2016(b) | | 25 |
| | (a) |
| | 25 |
| |
Change in estimates(c) | | 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 | 1 |
| | — |
| | 1 |
| | (18 | ) | | (1 | ) | | (19 | ) | |
| Balance at December 31, 2016 | $ | 644 |
| (e) | $ | 6 |
| (d) | $ | 650 |
| (e) | |
| Balance at December 31, 2017 | | $ | 640 |
| (c) | $ | 4 |
| (d) | $ | 644 |
| (c) |
| |
| (a) | AccretionLess than $1 million. |
| |
| (b) | Ameren Missouri’s accretion expense was recordeddeferred as a decrease to regulatory liabilities. |
| |
| (c) | The ARO increase resultedBalance included $6 million and $15 million in a corresponding increase recorded to "Property, Plant,“Other current liabilities” on the balance sheet as of December 31, 2017 and Equipment, Net." Ameren and Ameren Missouri increased their AROs related to the decommissioning of the Callaway energy center by $99 million to reflect the 2015 cost study and funding analysis filed with the MoPSC, the extension of the estimated operating life until 2044, and a reduction in the discount rate assumption. See Note 10 – Callaway Energy Center for additional information. In addition, as a result of new federal regulations, Ameren and Ameren Missouri recorded an increase of $100 million to their AROs associated with CCR storage facilities. See Note 15 – Commitments and Contingencies for additional information. Ameren and Ameren Missouri also increased their AROs by $4 million due to a change in the estimated retirement dates of the Meramec and Rush Island energy centers as a result of the MoPSC's April 2015 electric rate order.2016, respectively. |
| |
| (d) | Included in “Other deferred credits and liabilities” on the balance sheet. |
| |
| (e) | Balance included $5 millionAmeren 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 $15 millionfunding analysis filed with the MoPSC in "Other current liabilities" on2017, and an increase in the balance sheet as of December 31, 2015 and 2016, respectively.
assumed discount rate. |
See the Divestiture Transactions and Discontinued Operations section below for additional information on the AROs related to the abandoned Meredosia and Hutsonville energy centers, which are presented as discontinued operations and therefore not included in the table above.
Noncontrolling Interests
As of December 31, 20162017 and 2015,2016, Ameren’s noncontrolling interests included the preferred stock of Ameren Missouri and Ameren Illinois.
Operating Revenue
The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period.
Ameren Illinois participates in the performance-based formula ratemaking framework pursuant to the IEIMA.IEIMA and the FEJA. In addition, Ameren Illinois'Illinois’ and ATXI'sATXI’s electric transmission service operating revenues are regulated by the FERC. The provisions of the IEIMA and the FERC'sFERC’s electric transmission formula rate framework provide for annual reconciliations of the electric distribution and electric transmission service revenue requirements necessary 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'syear’s revenue requirement varies from the amount collected from customers, an adjustment is greater than the revenue requirement reflected in that year's customer rates, an increasemade to electric operating revenues with an offset to a regulatory asset is recordedor liability to reflect the expected recovery of those additional amountsthat year’s actual revenue requirement. The regulatory balance is then collected from, customers within two years. In each jurisdiction, if the current year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refundor refunded to, customers within two years. See Note 2 – Rate and Regulatory Matters for information regarding Ameren Illinois'Illinois’ revenue requirement reconciliation pursuant to the IEIMA.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, Ameren Missouri, and Ameren Illinois using settlement information provided by 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'sMissouri’s and Ameren Illinois'Illinois’ prior-period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof. In these cases, Ameren Missouri and Ameren Illinois recognize 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 no material MISO resettlements in 2017, 2016, 2015, or 2014.2015.
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“Operating Expenses – Fuel"Fuel” in the statement of income.
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 servicevesting period. See Note 1211 – 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'sMissouri’s electric and natural gas businesses and on Ameren Illinois'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'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,, 2015, and 2014:2015:
| | | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 151 |
| | $ | 156 |
| | $ | 151 |
| $ | 153 |
| | $ | 151 |
| | $ | 156 |
|
| Ameren Illinois | 57 |
| | 57 |
| | 64 |
| 57 |
| | 57 |
| | 57 |
|
| Ameren | $ | 208 |
| | $ | 213 |
| | $ | 215 |
| $ | 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 thatthe 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 recognizeexpect that regulators will probably 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.
Investment To the extent deferred tax credits used on tax returns for prior years have beenbalances are included in rate base, the revaluation of deferred taxes is recorded as a noncurrent liability. The credits are being amortized over the useful lives of the related investment. Deferred income taxes were recordedregulatory asset or liability on the temporary difference represented bybalance sheet and will be collected from or refunded to customers. For deferred tax balances not included in rate base, the revaluation of deferred investmenttaxes is recorded as an adjustment to income tax credits and a corresponding regulatory liability. This recognizesexpense on the expected reduction in rates for future lower income taxes associated with the amortization of the investment tax credits.statement. See Note 1312 – Income Taxes.Taxes for further information regarding both the revaluation of deferred taxes related to the TCJA.
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 which would be owed or refunded had the party been separately subject to tax considering the impact of consolidation. Any net benefit attributable to the parentAmeren (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, 1.0 million, and 1.81.0 million for the years ended December 31, 2017, 2016, 2015, and 2014,2015, respectively. There were no potentially dilutive securities excluded from the diluted earnings per share calculations for the years ended December 31, 2017, 2016, 2015, and 2014.
Capital Contributions and Return of Capital
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 Ameren Missouri 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 received cash capital contributions of $25 million from Ameren (parent).
In 2014, Ameren Missouri and Ameren Illinois received cash capital contributions of $215 million and $15 million, respectively, from Ameren (parent) as a result of the tax allocation agreement. Additionally, as of December 31, 2014, Ameren Missouri accrued a $9 million capital contribution related to the same agreement. Also in 2014, Ameren Missouri returned capital of $215 million to Ameren (parent).
Divestiture Transactions and Discontinued Operations
In December 2013 and January 2014, Ameren completed the divestiture of New AER to IPH. The transaction agreement with IPH provided that if the Elgin, Gibson City, and Grand Tower natural-gas-fired energy centers were subsequently sold by Medina Valley and Medina Valley received additional proceeds from such sale, Medina Valley would pay Genco any proceeds from such sale, net of taxes andcertain other expenses, in excess of the $137.5 million previously paid to Genco. In January 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower natural-gas-fired energy centers to Rockland Capital for a total purchase price of $168 million. The agreement with Rockland Capital required a portion of the purchase price to be held in escrow until January 31, 2016, to fund certain indemnity obligations, if any, of Medina Valley. The Rockland Capital escrow balance of $14 million and the corresponding payable due to Genco was reflected on Ameren's December 31, 2015, consolidated balance sheet in "Other current assets" and in "Other current liabilities," respectively. In 2016, Medina Valley received the amount held in escrow from Rockland Capital and paid Genco its portion of the escrow.
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.
The components of the assets Ameren also paid $25 million and liabilities of Ameren's discontinued operations at December 31, 2016 and 2015, consist primarily of AROs and the related deferred income tax assets associatedconcluded its obligations with the abandoned Meredosia and Hutsonville energy centers.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 also 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.customers, as well as separate presentation of alternative revenue programs on the income statement. Entities can apply the guidance retrospectively to each reporting period presented the(the full retrospective method,method), or retrospectively by recordingthey can record a cumulative effect adjustment to retained earnings in the period of initial adoption the(the modified retrospective method. The utility industry continues to assessmethod).
We have completed the impacts on accounting for contributions in aidevaluation of construction and similar arrangements, and collectibility, among other issues. The outcome of these assessments could have a significant impact on our results of operations and financial position. We plan to complete our assessment of the impactscontracts. Adoption of this guidance on our resultswill not result in material changes to the amount or timing of operations, financial position, presentationrevenue recognition. We will apply the guidance using the full retrospective method. We will include disaggregated revenue disclosures by segment and disclosures, and transition method,customer class in the next several months priorcombined notes to our adoption inthe financial statements. This guidance will be effective for the Ameren Companies for the first quarter of 2018.
Amendments toImproving the Consolidation AnalysisPresentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In February 2015,March 2017, the FASB issued authoritative guidance that amendsrequires an entity to report, including on a retrospective basis, the consolidation analysis for variable interest entitiesnon-service cost or income components of net benefit cost separately from the service cost component and voting interest entities. The new guidance affects (1) limited partnerships, similar legal entities, and certain investment funds, (2) the evaluationoutside of fees paid to a decision maker or service provider as a variable interest, (3) how fee arrangements impact the primary beneficiary determination, and (4) the evaluation of related party relationships on the primary beneficiary determination. Theoperating income. Our adoption of this guidance in 2016 did not impact the Ameren Companies' results of operations, financial position, cash flows, or disclosures.
Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share
In May 2015, to address diversity in practice, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the NAV practical expedient. The Ameren Companies have investments measured using the NAV practical expedient within the pension plan and postretirement benefit plan assets. We adopted this guidance on January 1, 2016 and retrospectively updated the presentation of these assetswill result in the fair value hierarchy tables included in Note 11 - Retirement Benefits. 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 adoption of this guidance did not impact our results of operations, financial position or cash flows.
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 requiresalso permits an entity to measure equity investments, other than those accountedcapitalize 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 undercapitalization. This change in the equity methodcapitalization of accounting, at fair value with changes in fair value recognized in net income. The recognition and measurementbenefit costs is not expected to affect our ability to recover total net benefit cost through customer rates. This guidance will be effective for the Ameren Companies in the first quarter of 2018, and requires
changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date. Also, 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 based on relevant information about past events, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. The credit loss guidance will be effective2018. See Note 10 – Retirement Benefits for the Ameren Companies in the first quartercomponents of 2020, and requires changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date. We are currently assessing the impacts of the new financial instruments guidance on our results of operations, financial position, and disclosures.
Leases
In February 2016, 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 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. We are currently assessing the impacts of this guidance for other effects on our results of operations, cash flows and disclosures. We expect to adopt this guidance in the first quarter of 2019. See Note 15 – Commitments and Contingencies for additional information on our leases.
Improvements to Employee Share-Based Payment Accounting
In March 2016, the FASB issued authoritative guidance that simplifies the accounting for share-based payment transactions, including the income tax consequences, the calculation of diluted earnings per share, the treatment of forfeitures, the classification of awards as either equity or liabilities, and the classification on the statement of cash flows. Ameren determines for each performance share unit award whether the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes results in either an excess taxnet benefit or an excess tax deficit. Previously, excess tax benefits were recognized in "Other paid-in capital" on Ameren’s consolidated balance sheet, and in certain cases, excess tax deficits were recognized in “Income taxes” on Ameren’s consolidated income statement. The new guidance increases income statement volatility by requiring all excess tax benefits and deficits to be recognized in “Income taxes,” and treated as discrete items in the period in which they occur. Ameren adopted this guidance in 2016 and prospectively applied the amendment in this guidance requiring recognition of excess tax benefits and deficits in the income statement, which resulted in recognition of
a $21 million income tax benefit and a corresponding $21 million increase in income from continuing operations and net income (9 cents per diluted share) during the period. Also as a result of the adoption of this guidance, Ameren made an accounting policy election to continue to estimate the number of forfeitures expected to occur. The amendments in the guidance that require application using a modified retrospective transition method did not impact Ameren. Therefore, there was no cumulative-effect adjustment to retained earnings recognized as of January 1, 2016. Ameren applied the amendments in this guidance relating to classification on the statement of cash flows retrospectively. For the year ended December 31, 2015, Ameren reclassified $2 million of excess tax benefits on the statement of cash flows from financing to operating activity. Also, for the years ended December 31, 2015 and December 31, 2014, Ameren reclassified $12 million and $14 million, respectively, of employee payroll taxes related to share-based payments from operating to financing activity.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 shown 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 loss guidance will be effective for the Ameren Companies in the first quarter of 2020. It requires changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date.
Leases
In February 2016, 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 accounted 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. 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.
Reclassification of Certain Tax Effects from Accumulated OCI
In February 2018, the FASB issued authoritative guidance allowing a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the TCJA. This optional reclassification can be applied retrospectively to December 31, 2017, or in the period of adoption. We are currently assessing whether we will elect to perform such a reclassification and the potential impact.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.
Missouri
FebruaryMarch 2017 Unanimous Stipulation and AgreementElectric Rate Order
In July 2016, Ameren Missouri filed a request withMarch 2017, the MoPSC seeking approval to increase its annual revenues for electric service. Relating to that request, in February 2017, Ameren Missouri, the MoPSC staff, the MoOPC, and all intervenors filedissued an order approving a unanimous stipulation and agreement with the MoPSC.in Ameren Missouri’s July 2016 regulatory rate review. The stipulation and agreement, which is subject to MoPSC approval, would resultorder resulted in a $3.4 billion revenue requirement, which iswas a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared to itswith the prior revenue requirement established in the MoPSC'sMoPSC’s April 2015 electric rate order. The stipulationnew rates, base level of expenses, and agreement did not specify the common equity percentage, the rate base, or the allowed returnamortizations became effective on common equity. The new revenue requirement reflects the current actual sales volumes of the New Madrid Smelter, whose operations remain suspended, as well as other agreed upon sales volumes.April 1, 2017.
The stipulation and agreement includesorder authorized the continued use of the FAC and the regulatory tracking mechanisms for pension and postretirement benefits, uncertain income tax positions, and renewable energy standards that the MoPSC previously authorized in earlier electric rate orders. These regulatory tracking mechanisms provide for a base level of expense to be reflected in Ameren Missouri’s base electric rates with differences inbetween the base amount and the actual expenses incurred recordeddeferred as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs under the stipulation and agreement would decreasedecreased by $54 million from the base level established in the MoPSC'sMoPSC’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, would reducereduced expenses by $26 million from the base levels established in the MoPSC'sMoPSC’s April 2015 electric rate order.
The stipulation and agreement contemplates that new rates will become effective on or before March 20, 2017. 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.
Noranda and New Madrid Smelter
In the first quarter of 2016, Noranda, which was historically Ameren Missouri's largest customer, suspended operations at the New Madrid Smelter and filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. Operations at the New Madrid Smelter remain suspended and Ameren Missouri is uncertain of future sales to the smelter. As a result, Ameren Missouri will not fully recover its revenue requirement until rates are adjusted prospectively by the MoPSC to accurately reflect the actual sales volumes to the New Madrid Smelter. As of December 31, 2016, Ameren Missouri has been paid in full for all previous electric service amounts, and expects to continue to be paid in full for the minimal amount of electric service it is currently providing to the New Madrid Smelter.
MEEIA
In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a stipulation and agreement betweenamong 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 ana certain input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District. In December 2016, the Missouri Court of Appeals, Western District, upheld the November 2015 MoPSC order. Ameren Missouri hasthen appealed thethat decision to uphold the MoPSC order to the Missouri Supreme Court. If the decision is overturned, Ameren Missouri would recognize an additional $9 million MEEIA 2013 performance incentive.
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 this order and in accordance with revenue recognition guidance, Ameren Missouri will recognize $5 million of additional revenues in the first quarter of 2018 relating 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 electric 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 95-mile 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 April 2016,January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. Before startingATXI plans to begin construction ATXI must obtain assents for road crossings fromin the five counties where the line will be constructed. Nonesecond quarter of the five county commissions have approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in each of the five county circuit courts to obtain the assents. A decision in each of the five lawsuits is expected in 2017. ATXI plans2018 and to complete the project in 2019; however, further delays in obtainingby the assents could delay the completion date. end of 2019.
Illinois
IEIMA & FEJA
Under the provisions of the IEIMA's performance-baseda formula rate-makingratemaking framework which currently extendseffective through 2022, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs.costs and allowed return on equity. The formula ratemaking framework qualifies as an alternative revenue program under GAAP. Each year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement reflected in customer 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 based on that year's actual recoverable costs incurred.ICC. As of December 31, 2017, Ameren Illinois had recorded regulatory assets 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 regulatory assets of $23 million anda $68 million, including interest, to reflect its expected 2016 and the 2015 approved revenue requirement reconciliation adjustments, respectively. As of December 31, 2015, Ameren Illinois had recorded a $103 million regulatory asset to reflect its approved 20142015 revenue requirement reconciliation adjustment, which was collected, with interest, from customers during 2016.2017.
In December 2016,2017, the ICC issued an order in Ameren Illinois’ annual update filing approvingthat approved a $14$17 million decrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2017.2018. This update reflectsreflected an increase to the annual formula rate based on 20152016 actual recoverable costs and expected net plant additions for 2016,2017, as well as an increase to include the 20152016 revenue requirement reconciliation adjustment, which was initially recorded as a regulatory assetadjustment. The increases in 2015, andthe update filing were more than offset by a decrease for the conclusion of the 20142015 revenue requirement reconciliation adjustment, which was fully collected from customers in 2016.
FEJA2017, consistent with the ICC’s December 2016 annual update filing order.
The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking processframework through 2022, and clarifying that a common equity ratio of up to and including 50% is prudent. Also, beginningBeginning in 2017, the FEJA decouplespermitted Ameren Illinois to recover, within the following two years, its electric distribution revenues established inrevenue requirement for a rate proceeding fromgiven 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 by providing that anydue to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue changes driven byrecognition 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 sales volumes differing from
sales volumes reflected in that year's rates will be collected from or refunded to customers within two years. This portionrecoverable costs, and it recognizes revenue associated with the expected return on its rate base ratably over the year. The decoupling provisions of the law extends beyondFEJA do not expire at the end of the IEIMA in 2022. Through 2022, revenue differences will be included in the annual IEIMA revenue requirement reconciliation. Additionally, this law creates a customer surcharge relating to certain nuclear energy centers located in Illinois that, 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.
Beginning as early as June 2017, theThe FEJA will allowallows Ameren Illinois to earn a return on its electric energy efficiencyenergy-efficiency program investments. Ameren IllinoisIllinois’ electric energy efficiencyenergy-efficiency investments will beare deferred as a regulatory asset and will earn a return at the company’s weighted averageweighted-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 efficiencyenergy-efficiency investments can also be increased or decreased by up to 200 basis points, baseddepending on the achievement of annual energy savings goals. The FEJA increased the level of electric energy efficiencyenergy-efficiency saving targets through 2030. Based on a formula provided inIn June 2017, pursuant to the act,FEJA, Ameren Illinois estimates it can annuallyfiled with the ICC an energy-efficiency plan for 2018 through 2021. In September 2017, the ICC issued an order approving Ameren Illinois’ implementation of the FEJA electric energy-efficiency savings targets and investments. Ameren Illinois plans to invest up to $100$99 million per year in electric energy-efficiency programs from 2018 through 2021, up2021. Ameren Illinois plans to $107 million annuallymake similar yearly investments in electric energy-efficiency programs from 2022 through 2025, and up to $114 million annually from 2026 through 2030. The ICC has the ability to lower thereduce electric energy efficiency savingenergy-efficiency savings goals if there are insufficient cost effective measures available.cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy efficiencyenergy-efficiency program investments and the return on those investments will be recoveredcollected from customers through a rider, andrider; they will not be included in the IEIMA formula ratemaking framework.
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, 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. 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. In an attempt to reduce regulatory lag, Ameren Illinois used a 2019 future test year in this proceeding.
A decision by the ICC in this proceeding is required by December 2018, with new rates expected to be effective in January 2019. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, nor whether any rate changes 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 Project
In August 2017, the Illinois Circuit Court 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. In November 2017, ATXI appealed this decision to the Illinois Supreme Court. ATXI plans to complete the project by the end of 2019; however, delays associated with 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 affected by these proceedings.
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 equity for FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a final 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 2015 to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of thea 50 basis point incentive adder for participation in an RTO. The order was consistent with the initial decision an administrative law judge issued in December 2015, and requiresrequired 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 15-month period ended February 2015. In addition, the newNovember 2013 complaint case. The 10.82% total allowed return on common equity ishas been reflected in rates since September 2016. The 10.82% allowed return on common equity may be replaced prospectively fromafter the September 2016 effective date ofFERC issues a final order in the order. Refunds for the November 2013February 2015 complaint case, are expected to be issued in the first half of 2017.discussed below.
AsSince 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 seeks a further reduction in the allowed base return on common equity for the FERC-regulated
transmission rate base under the MISO tariff to 8.67%.tariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which ifcase. 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 thea 50 basis point incentive adder for participation in an RTO. It would also require the issuance of customer refunds, with interest, for thethat 15-month period ended May 2016. Theperiod. A final FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. That final order will determine the allowed return on common equity for the 15-month period ended May 2016. That final order willwould also establish the allowed return on common equity that will apply prospectively from its expected second quarter 2017the effective date of such order, replacing the current 10.82% total return on common equity, which became effective in September 2016. equity.The 12.38% allowed return on common equity was effective for the period that began at the conclusiontiming of the 15-month period for the February 2015 complaint case in May 2016 through the September 2016 effective dateissuance of the final order in the November 2013February 2015 complaint case.case is uncertain for two reasons. First, while the FERC reestablished 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
Beginning with
Columbia Circuit vacated and remanded to the January 2015 effective date,FERC an order in a separate case in which the RTO participation incentive adder reduces any refund to customers relating to a reduction ofFERC established the allowed base return on common equity frommethodology used in the two MISO complaint cases discussed above and has been applied prospectively fromdescribed above. Ameren is unable to predict the effective dateimpact 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 2016 FERC order, resulting in2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a currentmotion to dismiss 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 10.82%.Appeals for the District of Columbia Circuit, as discussed above. FERC is under no deadline to issue an order on this motion.
As of December 31, 2016,2017, Ameren and Ameren Illinois
recorded current regulatory liabilities of $62$42 million and $42$25 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the September 2016 FERC order and the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reduction in the FERC-allowed base return on common equity would be material to its results of operations, financial position, or liquidity.
MISO Federal Income Tax Proceeding
In February 2018, MISO transmission owners with forward-looking rate formulas, including Ameren Illinois and ATXI, filed a request with the FERC to allow revisions to their 2018 electric transmission rates to reflect the 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. Absent 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.
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'sMissouri’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, 20162017 and 2015:2016: |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
| | | | | 2016 | | 2015 | | 2017 | | 2016 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Current regulatory assets: | | | | | | | | | | | | | | |
Under-recovered FAC(a)(b) | | $ | 21 |
| | $ | — |
| | $ | 21 |
| | | $ | 37 |
| | $ | — |
| | $ | 37 |
| |
Under-recovered Illinois electric power costs(c) | | — |
| | 3 |
| | 3 |
| | | — |
| | 3 |
| | 3 |
| |
Under-recovered PGA(c) | | — |
| | 4 |
| | 4 |
| | | — |
| | 8 |
| | 8 |
| |
MTM derivative losses(d) | | 9 |
|
| 15 |
| | 24 |
| | | 29 |
| | 45 |
| | 74 |
| |
Energy efficiency riders(e) | | 5 |
| | — |
| | 5 |
| | | 23 |
| | — |
| | 23 |
| |
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 68 |
| | 68 |
| | | — |
| | 103 |
| | 103 |
| |
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 7 |
| | 13 |
| | | — |
| | 8 |
| | 12 |
| |
VBA rider(a)(h) | | — |
| | 11 |
| | 11 |
| | | — |
| | — |
| | — |
| |
| Other | | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
| Total current regulatory assets | | $ | 35 |
| | $ | 108 |
| | $ | 149 |
| | | $ | 89 |
| | $ | 167 |
| | $ | 260 |
| | $ | 56 |
| | $ | 87 |
| | $ | 144 |
| | | $ | 35 |
| | $ | 108 |
| | $ | 149 |
|
| Noncurrent regulatory assets: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pension and postretirement benefit costs(i) | | $ | 175 |
| | $ | 319 |
| | $ | 494 |
| | | $ | 95 |
| | $ | 202 |
| | $ | 297 |
| | $ | 84 |
| | $ | 215 |
| | $ | 299 |
| | | $ | 175 |
| | $ | 319 |
| | $ | 494 |
|
Income taxes(j) | | 229 |
| | 1 |
| | 230 |
| | | 247 |
| | 4 |
| | 251 |
| | 139 |
| | 56 |
| | 197 |
| | | 229 |
| | 1 |
| | 230 |
|
Uncertain tax positions tracker(a)(k) | | 7 |
| | — |
| | 7 |
| | | 7 |
| | — |
| | 7 |
| | 5 |
| | — |
| | 5 |
| | | 7 |
| | — |
| | 7 |
|
ARO(l) | | — |
| | 3 |
| | 3 |
| | | — |
| | 4 |
| | 4 |
| | — |
| | 1 |
| | 1 |
| | | — |
| | 3 |
| | 3 |
|
Callaway costs(a)(m) | | 29 |
| | — |
| | 29 |
| | | 32 |
| | — |
| | 32 |
| | 25 |
| | — |
| | 25 |
| | | 29 |
| | — |
| | 29 |
|
Unamortized loss on reacquired debt(a)(n) | | 65 |
| | 59 |
| | 124 |
| | | 69 |
| | 69 |
| | 138 |
| | 61 |
| | 49 |
| | 110 |
| | | 65 |
| | 59 |
| | 124 |
|
Environmental cost riders(o) | | — |
| | 196 |
| | 196 |
| | | — |
| | 230 |
| | 230 |
| | — |
| | 173 |
| | 173 |
| | | — |
| | 196 |
| | 196 |
|
MTM derivative losses(d) | | 9 |
|
| 178 |
| | 187 |
|
|
| 15 |
| | 175 |
| | 190 |
| | 4 |
|
| 192 |
| | 196 |
|
|
| 9 |
| | 178 |
| | 187 |
|
Storm costs(a)(p) | | — |
| | 15 |
| | 15 |
| | | — |
| | 9 |
| | 9 |
| | — |
| | 10 |
| | 10 |
| | | — |
| | 15 |
| | 15 |
|
Demand-side costs before the MEEIA implementation(a)(q) | | 18 |
| | — |
| | 18 |
| | | 31 |
| | — |
| | 31 |
| | 11 |
| | — |
| | 11 |
| | | 18 |
| | — |
| | 18 |
|
Workers’ compensation claims(r) | | 6 |
| | 7 |
| | 13 |
| | | 6 |
| | 7 |
| | 13 |
| | 5 |
| | 7 |
| | 12 |
| | | 6 |
| | 7 |
| | 13 |
|
Credit facilities fees(s) | | 4 |
| | — |
| | 4 |
| | | 4 |
| | — |
| | 4 |
| | 3 |
| | — |
| | 3 |
| | | 4 |
| | — |
| | 4 |
|
Construction accounting for pollution control equipment(a)(t) | | 19 |
| | — |
| | 19 |
| | | 20 |
| | — |
| | 20 |
| | 18 |
| | — |
| | 18 |
| | | 19 |
| | — |
| | 19 |
|
Solar rebate program(a)(u) | | 49 |
| | — |
| | 49 |
| | | 74 |
| | — |
| | 74 |
| | 31 |
| | — |
| | 31 |
| | | 49 |
| | — |
| | 49 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 23 |
| | 23 |
| | | — |
| | 62 |
| | 62 |
| | — |
| | 54 |
| | 54 |
| | | — |
| | 23 |
| | 23 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 8 |
| | 10 |
| | | — |
| | 5 |
| | 11 |
| | — |
| | 16 |
| | 27 |
| | | — |
| | 8 |
| | 10 |
|
FEJA energy-efficiency riders(a)(v) | | | — |
| | 41 |
| | 41 |
| | | — |
| | — |
| | — |
|
| Other | | 9 |
| | 7 |
| | 16 |
| | | 5 |
| | 4 |
| | 9 |
| | 9 |
| | 8 |
| | 17 |
| | | 9 |
| | 7 |
| | 16 |
|
| Total noncurrent regulatory assets | | $ | 619 |
| | $ | 816 |
| | $ | 1,437 |
| | | $ | 605 |
| | $ | 771 |
| | $ | 1,382 |
| | $ | 395 |
| | $ | 822 |
| | $ | 1,230 |
| | | $ | 619 |
| | $ | 816 |
| | $ | 1,437 |
|
| Current regulatory liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Over-recovered FAC(b) | | $ | — |
| | $ | — |
| | $ | — |
| | | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Over-recovered Illinois electric power costs(c) | | — |
| | 25 |
| | 25 |
| | | — |
| | 6 |
| | 6 |
| | — |
| | 16 |
| | 16 |
| | | — |
| | 25 |
| | 25 |
|
Over-recovered PGA(c) | | — |
| | — |
| | — |
| | | 3 |
| | — |
| | 3 |
| | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
MTM derivative gains(d) | | 12 |
| | 11 |
| | 23 |
|
| | 16 |
| | 1 |
| | 17 |
| | 13 |
| | — |
| | 13 |
|
| | 12 |
| | 11 |
| | 23 |
|
Estimated refund for FERC complaint cases(v) | | — |
| | 42 |
| | 62 |
| | | — |
| | 32 |
| | 45 |
| |
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 | | $ | 12 |
| | $ | 78 |
| | $ | 110 |
| | | $ | 28 |
| | $ | 39 |
| | $ | 80 |
| | $ | 19 |
| | $ | 92 |
| | $ | 128 |
| | | $ | 12 |
| | $ | 78 |
| | $ | 110 |
|
| Noncurrent regulatory liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income taxes(w) | | $ | 33 |
| | $ | 4 |
| | $ | 37 |
| | | $ | 36 |
| | $ | 6 |
| | $ | 42 |
| |
Income taxes(j) | | | $ | 1,392 |
| | $ | 842 |
| | $ | 2,323 |
| | | $ | 33 |
| | $ | 4 |
| | $ | 37 |
|
Uncertain tax positions tracker(k) | | 3 |
| | — |
| | 3 |
| | | 6 |
| | — |
| | 6 |
| | 2 |
| | — |
| | 2 |
| | | 3 |
| | — |
| | 3 |
|
Asset removal costs(x) | | 970 |
| | 697 |
| | 1,669 |
| | | 933 |
| | 671 |
| | 1,605 |
| | 995 |
| | 725 |
| | 1,725 |
| | | 970 |
| | 697 |
| | 1,669 |
|
ARO(l) | | 162 |
| | — |
| | 162 |
| | | 167 |
| | — |
| | 167 |
| | 223 |
| | — |
| | 223 |
| | | 162 |
| | — |
| | 162 |
|
Bad debt rider(y) | | — |
| | 3 |
| | 3 |
| | | — |
| | 6 |
| | 6 |
| | — |
| | 2 |
| | 2 |
| | | — |
| | 3 |
| | 3 |
|
Pension and postretirement benefit costs tracker(z) | | 35 |
| | — |
| | 35 |
| | | 19 |
| | — |
| | 19 |
| | 35 |
| | — |
| | 35 |
| | | 35 |
| | — |
| | 35 |
|
Energy efficiency riders(e) | | — |
| | 45 |
| | 45 |
| | | — |
| | 36 |
| | 36 |
| |
Renewable energy credits(aa) | | — |
| | 15 |
| | 15 |
| | | — |
| | 12 |
| | 12 |
| |
Energy-efficiency riders(e) | | | — |
| | — |
| | — |
| | | — |
| | 45 |
| | 45 |
|
Renewable energy credits and zero-emission credits(aa) | | | — |
| | 58 |
| | 58 |
| | | — |
| | 15 |
| | 15 |
|
Storm tracker(ab) | | 7 |
| | — |
| | 7 |
| | | 9 |
| | — |
| | 9 |
| | 6 |
| | — |
| | 6 |
| | | 7 |
| | — |
| | 7 |
|
| Other | | 5 |
| | 4 |
| | 9 |
| | | 2 |
| | 1 |
| | 3 |
| | 11 |
| | 2 |
| | 13 |
| | | 5 |
| | 4 |
| | 9 |
|
| Total noncurrent regulatory liabilities | | $ | 1,215 |
| | $ | 768 |
| | $ | 1,985 |
| | | $ | 1,172 |
| | $ | 732 |
| | $ | 1,905 |
| | $ | 2,664 |
| | $ | 1,629 |
| | $ | 4,387 |
| | | $ | 1,215 |
| | $ | 768 |
| | $ | 1,985 |
|
| |
| (a) | These assets earn a return. |
| |
| (b) | 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) | Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. |
| |
| (d) | 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, and the throughput disincentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, net shared benefits, and the throughput disincentive 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. |
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'Illinois’ electric distribution service annual revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. TheAny under-recovery or over-recovery will be recovered from or refunded to customers with interest within two years. |
| |
| (g) | Ameren Illinois'Illinois’ and ATXI'sATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC'sFERC’s electric transmission formula ratemaking framework. TheAny under-recovery or over-recovery will be recovered from or refunded to customers within two years. |
| |
| (h) | Under-recovered natural gas sales volumes, including deviations from normal weather conditions. Each year'syear’s amount will be recovered from, or refunded to, customers from April through December of the following year. |
| |
| (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 1110 – Retirement Benefits for additional information. |
| |
| (j) | Tax benefitsThe regulatory assets represent deferred income taxes that will be recovered from customers related to the equity component of allowance for funds used during construction as well asand the effects of tax rate changes. This amountchanges from the TCJA and the increased income tax rate in Illinois. The regulatory liabilities represent deferred income taxes that will be recoveredrefunded 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 1312 – Income Taxes for additional information. |
| |
| (l) | 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'scenter’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 1514 – 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 efficiencyenergy-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 10-yeartwo-year period that began in March 2009.April 2017. Costs incurred from October 2008 through December 2009 are no longer being amortized until May 2017. Costs incurred from January 2010 through February 2011 are being amortized overas of April 2017, and a six-yearnew amortization period that beganfor these costs will be determined in August 2011. Costs incurred from March 2011 through July 2012 are being amortized over a six-year period that began in January 2013.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. The February 2017 stipulation and agreement, if approved, would modify these amortization periods. |
| |
| (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 intoin 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'sMissouri’s solar rebate program to fulfill its renewable energy portfolio requirement. These costsCosts 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 June 2015. The February 2017 stipulation and agreement, if approved, would modify this amortization period.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 FERC orders. Seethe February 2015 FERC Complaint CasesCase discussed above. |
| |
(w) | Unamortized portion of investment tax credits and reductions to deferred tax liabilities recorded at rates in excess of current statutory rates. The unamortized portion of investment tax credits and the reduction to deferred tax liabilities are being amortized over the expected life of the underlying assets. |
| |
| (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 20142015 was refunded to customers from June 2015 through May 2016. The over-recovery relating to 2015 is being refunded to customers from June 2016 through May 2017. The over-recovery relating to 2016 will beis 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 tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs included in customer rates. For periodscosts 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 AprilMoPSC’s May 2015 electric rate order directed the amortization period to occur over three to five years, beginninga five-year period that began in June 2015. For periodscosts incurred between January 2012 and December 2016, the MoPSC’s March 2017 electric rate order directed the amortization period to occur over a five-year period that began in April 2017. For costs incurred after December 2014,2016, the amortization period will be determined in the July 2016a future electric regulatory rate case. The February 2017 stipulation and agreement, if approved, would modify these amortization periods.review. |
| |
| (aa) | Funds collected from customers and alternative retail electric suppliers for the purchase of renewable energy credits and zero-emission credits through IPA procurements for distributed generation.procurements. The balance will be amortized as renewable energythe credits are purchased. |
| |
| (ab) | A regulatory tracking mechanism at Ameren Missouri for the difference between the level of storm costs incurred in a particular year and the level of such costs included in rates. For periods prior to December 2014, the MoPSC'sMoPSC’s April 2015 electric rate order directed the amortization to occur over a five-year period that began in June 2015. For periods after December 2014, the amortization period will be determined in the July 2016MoPSC’s March 2017 electric rate case.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. The February 2017 stipulation and agreement, if approved, would modify these amortization periods. |
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, 20162017 and 20152016:
| | | | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) | | 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 |
| | $ | 10,911 |
| | $ | — |
| | $ | — |
| | $ | 10,911 |
|
| Electric distribution | | 5,563 |
| | 5,287 |
| | — |
| | 10,850 |
| | 5,563 |
| | 5,287 |
| | — |
| | 10,850 |
|
| Electric transmission | | 1,151 |
| | 2,016 |
| | 712 |
| | 3,879 |
| | 1,151 |
| | 2,016 |
| | 712 |
| | 3,879 |
|
| Natural gas | | 455 |
| | 2,186 |
| | — |
| | 2,641 |
| | 455 |
| | 2,186 |
| | — |
| | 2,641 |
|
Other(c) | | 879 |
| | 719 |
| | 239 |
| | 1,837 |
| | 879 |
| | 719 |
| | 239 |
| | 1,837 |
|
| | | 18,959 |
| | 10,208 |
| | 951 |
| | 30,118 |
| | 18,959 |
| | 10,208 |
| | 951 |
| | 30,118 |
|
| Less: Accumulated depreciation and amortization | | 7,880 |
| | 2,850 |
| | 231 |
| | 10,961 |
| | 7,880 |
| | 2,850 |
| | 231 |
| | 10,961 |
|
| | | 11,079 |
| | 7,358 |
| | 720 |
| | 19,157 |
| | 11,079 |
| | 7,358 |
| | 720 |
| | 19,157 |
|
| Construction work in progress: | | | | | | | | | | | | | | | | |
| Nuclear fuel in process | | 206 |
| | — |
| | — |
| | 206 |
| | 206 |
| | — |
| | — |
| | 206 |
|
| Other | | 193 |
| | 111 |
| | 446 |
| | 750 |
| | 193 |
| | 111 |
| | 446 |
| | 750 |
|
| Property and plant, net | | $ | 11,478 |
| | $ | 7,469 |
| | $ | 1,166 |
| | $ | 20,113 |
| |
| 2015 | | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | | |
| Electric generation | | $ | 10,431 |
| | $ | — |
| | $ | — |
| | $ | 10,431 |
| |
| Electric distribution | | 5,303 |
| | 4,952 |
| | — |
| | 10,255 |
| |
| Electric transmission | | 979 |
| | 1,674 |
| | 121 |
| | 2,774 |
| |
| Natural gas | | 445 |
| | 1,997 |
| | — |
| | 2,442 |
| |
Other(c) | | 808 |
| | 627 |
| | 266 |
| | 1,701 |
| |
| | | 17,966 |
| | 9,250 |
| | 387 |
| | 27,603 |
| |
| Less: Accumulated depreciation and amortization | | 7,460 |
| | 2,632 |
| | 255 |
| | 10,347 |
| |
| | | 10,506 |
| | 6,618 |
| | 132 |
| | 17,256 |
| |
| Construction work in progress: | | | | | | | | | |
| Nuclear fuel in process | | 275 |
| | — |
| | — |
| | 275 |
| |
| Other | | 402 |
| | 230 |
| | 636 |
| | 1,268 |
| |
| Property, plant, and equipment, net | | $ | 11,183 |
| | $ | 6,848 |
| | $ | 768 |
| | $ | 18,799 |
| | $ | 11,478 |
| | $ | 7,469 |
| | $ | 1,166 |
| | $ | 20,113 |
|
| |
| (a) | Amounts in Ameren and Ameren Missouri include two CTs under separate capital lease agreements. The gross cumulative asset value of those agreements was $232$233 million and $233$232 million at December 31, 20162017 and 2015,2016, respectively. The total accumulated depreciation associated with the two CTs was $77$83 million and $72$77 million at December 31, 2017 and 2016, respectively. See Note 5 – Long-term Debt and 2015, respectively. In addition, Ameren Missouri has investments in debt securities, classified as held-to-maturity and recorded in "Other assets" that are related to the two CTs from the city of Bowling Green and Audrain County. As of December 31, 2016 and 2015, the carrying value ofEquity Financings for additional information on these debt securities was $282 million and $288 million, respectively.capital lease agreements. |
| |
| (b) | The estimated lives for each asset group are as follows: 5 to 10072 years for electric generation, excluding Ameren Missouri'sMissouri’s hydro generating assets which have useful lives of up to 150 years, 1820 to 7580 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 multiple utilityelectric 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 gross carrying value of capitalized software, the related accumulated amortization, and the amortization expense of capitalized software by year:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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) | 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, 20162017, 20152016, and 20142015, which represent noncash investing activity excluded from the accompanying statements of cash flows:
| | | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | Ameren(a) | | Ameren Missouri | | Ameren Illinois |
| Accrued capital expenditures: | | | | | | | | | | |
| 2017 | | $ | 361 |
| | $ | 159 |
| | $ | 175 |
|
| 2016 | $ | 251 |
| | $ | 116 |
| | $ | 87 |
| 251 |
| | 116 |
| | 87 |
|
| 2015 | 235 |
| | 85 |
| | 92 |
| 235 |
| | 85 |
| | 92 |
|
| 2014 | 181 |
| | 72 |
| | 59 |
| |
| Accrued nuclear fuel expenditures: | | | | | | | | | | |
| 2017 | | 10 |
| | 10 |
| | (b) |
|
| 2016 | 20 |
| | 20 |
| | (b) |
| 20 |
| | 20 |
| | (b) |
|
| 2015 | 16 |
| | 16 |
| | (b) |
| 16 |
| | 16 |
| | (b) |
|
| 2014 | 13 |
| | 13 |
| | (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 intercompanyaffiliate borrowings.
Credit Agreements
In December 2016, theThe Credit Agreements were amended and restated. The amended and restated agreements, among other things, extended the maturity dates of the Credit Agreements and provide $2.1 billion of credit cumulatively through the extended maturity date. The Credit Agreements, which were previously scheduled to mature in December 2019, are now scheduled to mature in December 2021. 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 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 (the amount being each borrower's "Borrowing Sublimit"):facility: | | | | | Missouri Credit Agreement | Illinois Credit Agreement | | Missouri Credit Agreement | Illinois Credit Agreement |
| Ameren | | $ | 700 |
| $ | 500 |
| |
| Ameren (parent) | | | $ | 700 |
| $ | 500 |
|
| Ameren Missouri | | 800 |
| (a) |
| | 800 |
| (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$1.2 billion for the Missouri Credit Agreement and $1.3$1.3 billion for the Illinois Credit Agreement. Ameren (parent) borrowings are due and payable no
later than the maturity date of the Credit Agreement.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'sborrower’s long-term unsecured credit ratings or, if no such ratings are in effect, the borrower'sborrower’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$2.1 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 intercompanyaffiliate loan arrangements. Both of the Credit Agreements are available to Ameren to support issuances under Ameren's commercial paper program, subject to borrowing sublimits. The Missouri Credit Agreement and the Illinois Credit Agreement are available to support issuances under Ameren (parent)'s,’s, Ameren Missouri'sMissouri’s and Ameren Illinois'Illinois’ commercial paper programs, respectively.respectively, subject to borrowing
sublimits. As of December 31, 2016,2017, based on commercial paper outstanding and letters of credit issued under the Credit Agreements, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $1.5 billion.$1.6 billion.
Ameren, Ameren Missouri, and Ameren Illinois did not borrow under the Credit Agreements for the years ended December 31, 20162017 and 2015.
Commercial Paper
The following table summarizes the borrowing activity and relevant interest rates under Ameren (parent)'s,’s, Ameren Missouri'sMissouri’s and Ameren Illinois'Illinois’ commercial paper programs for the years ended December 31, 20162017 and 20152016:
| | | | | Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated | | 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 |
| | $ | 440 |
| | $ | 60 |
| $ | 52 |
| $ | 552 |
|
| Outstanding borrowings at period-end | | 507 |
| | — |
| 51 |
| 558 |
| | 507 |
| | — |
| 51 |
| 558 |
|
| Weighted-average interest rate | | 0.82 | % | | 0.74 | % | 0.69 | % | 0.80 | % | | 0.82 | % | | 0.74 | % | 0.69 | % | 0.80 | % |
Peak outstanding commercial paper during period(a) | | $ | 574 |
| | $ | 208 |
| $ | 195 |
| $ | 839 |
| | $ | 574 |
| | $ | 208 |
| $ | 195 |
| $ | 839 |
|
| Peak interest rate | | 1.05 | % | | 0.85 | % | 0.90 | % | 1.05 | % | | 1.05 | % | | 0.85 | % | 0.90 | % | 1.05 | % |
| 2015 | | | | | |
| Average daily commercial paper outstanding | | $ | 721 |
| | $ | 42 |
| $ | 4 |
| $ | 767 |
| |
| Outstanding borrowings at period-end | | 301 |
| | — |
| — |
| 301 |
| |
| Weighted-average interest rate | | 0.57 | % | | 0.50 | % | 0.44 | % | 0.55 | % | |
Peak outstanding commercial paper during period(a) | | $ | 874 |
| | $ | 294 |
| $ | 48 |
| $ | 1,108 |
| |
| Peak interest rate | | 0.91 | % | | 0.60 | % | 0.60 | % | 0.91 | % | |
| |
| (a) | The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of the peak amounts presented by company mightthe companies may not equal the Ameren Consolidatedconsolidated peak amount for the period. |
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 obtainment ofobtaining 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, 2016,2017, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 51%53%, 48%, 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 Agreementcredit 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$100 million in the
aggregate (including under the other Credit Agreement)credit agreement). However, under the default provisions of the Credit Agreements, any default of Ameren (parent) under any Credit Agreementeither 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.credit agreement. Further, the Credit AgreementAgreements default provisions provide that an Ameren (parent) default under anyeither of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.
None of the Ameren Companies'Companies’ credit 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 agreements at December 31, 20162017.
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 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 money pool for the year ended December 31, 20162017, was 1.19% (2016 – 0.52% (2015 –
0.11%).
See Note 1413 – Related PartyRelated-party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the years ended
December 31, 2017, 2016,, 2015, and 2014.
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, 20162017 and 20152016:
|
| | | | | | | |
| | 2016 | | 2015 |
| Ameren (Parent): | | | |
| 2.70% Senior unsecured notes due 2020 | $ | 350 |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | 350 |
| | 350 |
|
| Total long-term debt, gross | 700 |
| | 700 |
|
| Less: Unamortized debt issuance costs | (6 | ) | | (6 | ) |
| Long-term debt, net | $ | 694 |
| | $ | 694 |
|
| Ameren Missouri: | | | |
Senior secured notes:(a) | | | |
| 5.40% Senior secured notes due 2016 | — |
| | 260 |
|
| 6.40% Senior secured notes due 2017 | 425 |
| | 425 |
|
6.00% Senior secured notes due 2018(b) | 179 |
| | 179 |
|
| 5.10% Senior secured notes due 2018 | 199 |
| | 199 |
|
6.70% Senior secured notes due 2019(b) | 329 |
| | 329 |
|
| 5.10% Senior secured notes due 2019 | 244 |
| | 244 |
|
| 5.00% Senior secured notes due 2020 | 85 |
| | 85 |
|
| 3.50% Senior secured notes due 2024 | 350 |
| | 350 |
|
| 5.50% Senior secured notes due 2034 | 184 |
| | 184 |
|
| 5.30% Senior secured notes due 2037 | 300 |
| | 300 |
|
8.45% Senior secured notes due 2039(b) | 350 |
| | 350 |
|
3.90% Senior secured notes due 2042(b) | 485 |
| | 485 |
|
| 3.65% Senior secured notes due 2045 | 400 |
| | 250 |
|
| Environmental improvement and pollution control revenue bonds: | | | |
1992 Series due 2022(c)(d) | 47 |
| | 47 |
|
1993 5.45% Series due 2028(e) | (e) |
| | (e) |
|
1998 Series A due 2033(c)(d) | 60 |
| | 60 |
|
1998 Series B due 2033(c)(d) | 50 |
| | 50 |
|
1998 Series C due 2033(c)(d) | 50 |
| | 50 |
|
| Capital lease obligations: | | | |
| City of Bowling Green capital lease (Peno Creek CT) due 2022 | 42 |
| | 48 |
|
| Audrain County capital lease (Audrain County CT) due 2023 | 240 |
| | 240 |
|
| Total long-term debt, gross | 4,019 |
| | 4,135 |
|
| Less: Unamortized discount and premium | (6 | ) | | (6 | ) |
| Less: Unamortized debt issuance costs | (19 | ) | | (19 | ) |
| Less: Maturities due within one year | (431 | ) | | (266 | ) |
| Long-term debt, net | $ | 3,563 |
| | $ | 3,844 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| Ameren (Parent): | | | |
| 2.70% Senior unsecured notes due 2020 | $ | 350 |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | 350 |
| | 350 |
|
| Total long-term debt, gross | 700 |
| | 700 |
|
| Less: Unamortized debt issuance costs | (4 | ) | | (6 | ) |
| Long-term debt, net | $ | 696 |
| | $ | 694 |
|
| 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 |
|
5.00% Senior secured notes due 2020(a) | 85 |
| | 85 |
|
1992 Series bonds due 2022(c)(d) | 47 |
| | 47 |
|
3.50% Senior secured notes due 2024(a) | 350 |
| | 350 |
|
2.95% Senior secured notes due 2027(a) | 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 |
|
5.50% Senior secured notes due 2034(a) | 184 |
| | 184 |
|
5.30% Senior secured notes due 2037(a) | 300 |
| | 300 |
|
8.45% Senior secured notes due 2039(a)(b) | 350 |
| | 350 |
|
3.90% Senior secured notes due 2042(a)(b) | 485 |
| | 485 |
|
3.65% Senior secured notes due 2045(a) | 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 |
|
| Total long-term debt, gross | 3,988 |
| | 4,019 |
|
| Less: Unamortized discount and premium | (7 | ) | | (6 | ) |
| Less: Unamortized debt issuance costs | (20 | ) | | (19 | ) |
| Less: Maturities due within one year | (384 | ) | | (431 | ) |
| Long-term debt, net | $ | 3,577 |
| | $ | 3,563 |
|
| | | | 2016 | | 2015 | 2017 | | 2016 |
| Ameren Illinois: | | | | | | |
| Senior secured notes: | | | | |
| 6.20% Senior secured notes due 2016 | $ | — |
| | $ | 54 |
| |
| 6.25% Senior secured notes due 2016 | — |
| | 75 |
| |
| Bonds and notes: | | | | |
6.125% Senior secured notes due 2017(g)(h) | 250 |
| | 250 |
| $ | — |
| | $ | 250 |
|
6.25% Senior secured notes due 2018(g)(h) | 144 |
| | 144 |
| 144 |
| | 144 |
|
9.75% Senior secured notes due 2018(g)(h) | 313 |
| | 313 |
| 313 |
| | 313 |
|
2.70% Senior secured notes due 2022(g)(h) | 400 |
| | 400 |
| 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 |
| 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(g) | 60 |
| | 60 |
| 60 |
| | 60 |
|
6.70% Senior secured notes due 2036(g) | 61 |
| | 61 |
| |
1993 Series B-1 Senior unsecured notes due 2028(d)(k) | | 17 |
| | 17 |
|
6.70% Senior secured notes due 2036(f)(g) | 42 |
| | 42 |
| 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(l) | | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(g) | 280 |
| | 280 |
| 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(g) | 250 |
| | 250 |
| 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(g) | 490 |
| | 250 |
| 490 |
| | 490 |
|
| Environmental improvement and pollution control revenue bonds: | | | | |
5.90% Series 1993 due 2023(i) | (i) |
| | (i) |
| |
5.70% 1994A Series due 2024(j) | (j) |
| | (j) |
| |
1993 Series B-1 due 2028(d)(k) | 17 |
| | 17 |
| |
3.70% First mortgage bonds due 2047(m) | | 500 |
| | — |
|
| Total long-term debt, gross | 2,607 |
| | 2,496 |
| 2,857 |
| | 2,607 |
|
| Less: Unamortized discount and premium | — |
| | (7 | ) | (3 | ) | | — |
|
| Less: Unamortized debt issuance costs | (19 | ) | | (18 | ) | (24 | ) | | (19 | ) |
| Less: Maturities due within one year | (250 | ) | | (129 | ) | (457 | ) | | (250 | ) |
| Long-term debt, net | $ | 2,338 |
| | $ | 2,342 |
| $ | 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 | $ | 6,595 |
| | $ | 6,880 |
| $ | 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 Missouri senior secured notes currently outstanding, we do not expect the first mortgage bond lien protection associated with these notes to fall away before 2042. |
| |
| (b) | 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, 6.00% senior secured notes due 2018, 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) | 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'sMissouri’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 20162017 and 20152016 were as follows: |
| | | | 2016 | | 2015 | 2017 | | 2016 |
| Ameren Missouri 1992 Series due 2022 | 0.66% | | 0.06% | 1.43% | | 0.66% |
| Ameren Missouri 1998 Series A due 2033 | 0.91% | | 0.24% | 1.77% | | 0.91% |
| Ameren Missouri 1998 Series B due 2033 | 0.92% | | 0.24% | 1.75% | | 0.92% |
| Ameren Missouri 1998 Series C due 2033 | 0.97% | | 0.24% | 1.73% | | 0.97% |
| Ameren Illinois 1993 Series B-1 due 2028 | 0.70% | | 0.49% | 1.08% | | 0.70% |
| |
| (e) | These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and 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) | These notesPayments due to the lessor under these capital lease obligations are collaterally secured by first mortgagepaid 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 lessor and held by Ameren IllinoisMissouri. The timing and amounts of payments due from Ameren Missouri under its 1933 mortgage indenture.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 notes have a fall-away lien provision,balance of both the capital lease obligations and Ameren Illinois could cause these notes to become unsecured at any time by redeeming the pollution control bonds 5.90% Series 1993 due 2023 (of which less than $1related investments in debt securities, recorded in "Other Assets," was $276 million remains outstanding).and $282 million, respectively, as of December 31, 2017 and 2016. |
| |
| (g) | These notes are collaterally secured by 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. 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 Ameren Illinoismaturity date of these senior secured notes currently outstanding,and the 3.70% first mortgage bonds due 2047, we do not expect the mortgage bond lien protection associated with these notes to fall away before 2022.away. |
| |
| (h) | 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 and 6.125% senior secured notes due 2017 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 notes remain outstanding. |
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 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. |
| |
| (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, 20162017:
| | | | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | Ameren Consolidated | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated |
| 2017 | $ | — |
| | $ | 431 |
| | $ | 250 |
| | $ | 681 |
| |
| 2018 | — |
| | 383 |
| | 457 |
| | 840 |
| $ | — |
| | $ | 384 |
| | $ | 457 |
| | $ | — |
| | $ | 841 |
|
| 2019 | — |
| | 581 |
| | — |
| | 581 |
| — |
| | 581 |
| | — |
| | — |
| | 581 |
|
| 2020 | 350 |
| | 92 |
| | — |
| | 442 |
| 350 |
| | 92 |
| | — |
| | — |
| | 442 |
|
| 2021 | — |
| | 8 |
| | — |
| | 8 |
| — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| 2022 | | — |
| | 56 |
| | 400 |
| | 50 |
| | 506 |
|
| Thereafter | 350 |
| | 2,524 |
| | 1,900 |
| | 4,774 |
| 350 |
| | 2,867 |
| | 2,000 |
| | 400 |
| | 5,617 |
|
| Total | $ | 700 |
| | $ | 4,019 |
| | $ | 2,607 |
| | $ | 7,326 |
| $ | 700 |
| | $ | 3,988 |
| | $ | 2,857 |
| | $ | 450 |
| | $ | 7,995 |
|
| |
| (a) | Excludes unamortized discount, andunamortized premium, and debt issuance costs of $6$4 million, $2527 million, $27 million and $192 million at Ameren (parent), Ameren Missouri, and 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'sAmeren’s subsidiaries wasis included in "Noncontrolling Interests"“Noncontrolling Interests” on Ameren'sAmeren’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, 20162017 and 20152016:
| | | | | Redemption Price(per share) | | 2016 | | 2015 | | Redemption Price (per share) | | 2017 | | 2016 |
| 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 par value preferred stock authorized, with no such shares outstanding. Ameren Missouri has 7.5 million shares of $1 par value preference stock authorized, with no such shares outstanding. Ameren Illinois has 2.6 million shares of no par value preferred stock authorized, with no such shares outstanding.
Ameren
In November 2015, Ameren (parent) issued $350 million of 2.70% senior unsecured notes due in November 2020, with interest payable semiannually in May and November of each year, beginning in May 2016. Ameren (parent) received proceeds of $348 million, which were used to repay a portion of its short-
term debt.
In November 2015, Ameren (parent) issued $350 million of 3.65% senior unsecured notes due in February 2026, with interest payable semiannually in February and August of each year, beginning in February 2016. Ameren (parent) received proceeds of $347 million, which were used to repay a portion of its short-term debt.
In 2015,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 will expireexpires in June 2018.December 2020.
Ameren filed a Form S-3 registration statement with the SEC in 2014,May 2017, authorizing the offering of 8.66 million additional shares of its common stock under DRPlus, which expires in May 2017.2020. 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. As of December 31, 20162017 and 2015,2016, DRPlus participant funds of $8 million were reflected on Ameren'sAmeren’s consolidated balance sheets in "Other“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 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.
From 20142015 through 2016,2017, Ameren shares for its DRPlus and its 401(k) plans were purchased in the open market.
Ameren Missouri
In June 2017, Ameren Missouri issued $400 million of 2.95% senior secured notes due June 2027, with interest payable semiannually on June 15 and December 15 of each year, beginning December 15, 2017. Ameren Missouri 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 February 2016, $260 million principal amount of Ameren
Missouri's Missouri’s 5.40% senior secured notes matured and were repaid with cash on hand and commercial paper borrowings.
In June 2016, and April 2015, Ameren Missouri issued $150 million and $250 million, respectively, of 3.65% senior secured notes due in April 2045, with interest payable semiannually in April and October of each year, beginning in October 2016 and 2015, respectively.2016. Ameren Missouri received proceeds of $148 million from the June 2016 issuance, and $247 million from the April 2015 issuance, which were bothwas used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $114 million of its 4.75% senior secured notes that matured in April 2015.
For information on Ameren Missouri'sMissouri’s capital contributions, and return of capital, refer to Capital Contributions and Return of Capital in Note 113 – Summary of Significant Accounting Policies.Related-party Transactions.
Ameren Illinois
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 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, and 2015, Ameren Illinois issued $240 million and $250 million, respectively, of 4.15% senior secured notes due in March 2046, with interest payable semiannually in March and September, beginning in March 2017 and 2016, respectively.2017. Ameren Illinois received proceeds of $245 million from eachthe issuance, which were bothwas used to repay a portion of its short-term debt.
For information on Ameren Illinois'Illinois’ capital contributions, refer to Capital Contributions and Return of Capital in Note 113 – SummaryRelated-party Transactions.
ATXI
In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of Significant Accounting Policies.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, 20162017, 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 | 4.6 |
| $ | 4,077 |
| | >2.5 | 105.3 |
| $ | 2,344 |
| | >2.0 | 4.8 |
| $ | 4,222 |
| | >2.5 | 95.4 |
| $ | 2,118 |
| |
| Ameren Illinois | >2.0 | 6.9 |
| 3,819 |
| (d) | >1.5 | 2.8 |
| 203 |
| (e) | >2.0 | 7.1 |
| 4,119 |
| (d) | >1.5 | 2.9 |
| 203 |
| (e) |
| |
| (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 $1,2061,629 million and $279$529 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'Illinois’ articles of incorporation. |
Ameren'sAmeren’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 may not pay any dividend on its stock unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois 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, 20162017, 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, 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, 20162017, 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, letters of credit, and Ameren parent(parent) guarantee arrangements on behalf of its subsidiaries. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
NOTE 6 – OTHER INCOME AND EXPENSES
The following table presents the components of "Other“Other Income and Expenses"Expenses” in the Ameren Companies’ statements of income (loss) for the years ended December 31, 20162017, 20152016, and 20142015:
| | | | 2016 | | 2015 | | 2014 | | 2017 | | 2016 | | 2015 | |
Ameren:(a) | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
| Allowance for equity funds used during construction | $ | 27 |
| | $ | 30 |
| | $ | 34 |
| | $ | 24 |
| | $ | 27 |
| | $ | 30 |
| |
| Interest income on industrial development revenue bonds | 27 |
| | 27 |
| | 27 |
| | 26 |
| | 27 |
| | 27 |
| |
Interest income (b) | 13 |
| | 14 |
| | 10 |
| | 8 |
| | 13 |
| | 14 |
| |
| Other | 7 |
| | 3 |
| | 8 |
| (c) | 1 |
| | 7 |
| | 3 |
| |
| Total miscellaneous income | $ | 74 |
| | $ | 74 |
| | $ | 79 |
| | $ | 59 |
| | $ | 74 |
| | $ | 74 |
| |
| Miscellaneous expense: | | | | | | | | | | | | |
| Donations | $ | 16 |
| | $ | 15 |
| | $ | 10 |
| | $ | 8 |
| | $ | 16 |
| | $ | 15 |
| |
| Other | 16 |
| | 15 |
| | 12 |
| | 13 |
| | 16 |
| | 15 |
| |
| Total miscellaneous expense | $ | 32 |
| | $ | 30 |
| | $ | 22 |
| | $ | 21 |
| | $ | 32 |
| | $ | 30 |
| |
| Ameren Missouri: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
| Allowance for equity funds used during construction | $ | 23 |
| | $ | 22 |
| | $ | 32 |
| | $ | 21 |
| | $ | 23 |
| | $ | 22 |
| |
| Interest income on industrial development revenue bonds | 27 |
| | 27 |
| | 27 |
| | 26 |
| | 27 |
| | 27 |
| |
| Interest income | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| |
| Other | 1 |
| | 2 |
| | — |
| | — |
| | 1 |
| | 2 |
| |
| Total miscellaneous income | $ | 52 |
| | $ | 52 |
| | $ | 60 |
| | $ | 48 |
| | $ | 52 |
| | $ | 52 |
| |
| Miscellaneous expense: | | | | | | | | | | | | |
| Donations | $ | 4 |
| | $ | 5 |
| | $ | 6 |
| | $ | 2 |
| | $ | 4 |
| | $ | 5 |
| |
| Other | 6 |
| | 6 |
| | 6 |
| | 6 |
| | 6 |
| | 6 |
| |
| Total miscellaneous expense | $ | 10 |
| | $ | 11 |
| | $ | 12 |
| | $ | 8 |
| | $ | 10 |
| | $ | 11 |
| |
| Ameren Illinois: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
| Allowance for equity funds used during construction | $ | 4 |
| | $ | 8 |
| | $ | 2 |
| | $ | 3 |
| | $ | 4 |
| | $ | 8 |
| |
Interest income (b) | 12 |
| | 12 |
| | 7 |
| | 7 |
| | 12 |
| | 12 |
| |
| Other | 5 |
| | 1 |
| | 8 |
| (c) | 1 |
| | 5 |
| | 1 |
| |
| Total miscellaneous income | $ | 21 |
| | $ | 21 |
| | $ | 17 |
| | $ | 11 |
| | $ | 21 |
| | $ | 21 |
| |
| Miscellaneous expense: | | | | | | | | | | | | |
| Donations | $ | 6 |
| | $ | 5 |
| | $ | 4 |
| | $ | 5 |
| | $ | 6 |
| | $ | 5 |
| |
| Other | 6 |
| | 7 |
| | 4 |
| | 5 |
| | 6 |
| | 7 |
| |
| Total miscellaneous expense | $ | 12 |
| | $ | 12 |
| | $ | 8 |
| | $ | 10 |
| | $ | 12 |
| | $ | 12 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | Includes Ameren Illinois'Illinois’ interest income on the IEIMA revenue requirement reconciliation adjustment regulatory assets. |
| |
(c) | Includes Ameren Illinois' income earned in 2014 from customer-requested construction. |
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.
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, 20162017 and 2015.2016. As of December 31, 2016,2017, these contracts extended through October 2019, March 2021,2023, May 2032, and February 2020September 2021 for fuel oils, natural gas, power, and uranium, respectively.
| | | | Quantity (in millions, except as indicated) | Quantity (in millions, except as indicated) |
| | 2016 | 2015 | 2017 | 2016 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
Fuel oils (in gallons)(a) | 30 | (b) | 30 | 35 | (b) | 35 | 28 |
| (b) |
| 28 |
| 30 |
| (b) |
| 30 |
|
| Natural gas (in mmbtu) | 25 | 129 | 154 | 30 | 151 | 181 | 24 |
| 139 |
| 163 |
| 25 |
| 129 |
| 154 |
|
| Power (in megawatthours) | 1 | 9 | 10 | 1 | 10 | 11 | 3 |
| 9 |
| 12 |
| 1 |
| 9 |
| 10 |
|
| Uranium (pounds in thousands) | 345 | (b) | 345 | 494 | (b) | 494 | 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.
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, 20162017 and 2015,2016, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral.
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, 20162017 and 20152016:
| | | | | 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) |
| | Balance Sheet Location | | Ameren Missouri | | Ameren Illinois | | Ameren | Total liabilities (c) | $ | 9 |
| $ | 217 |
| $ | 226 |
| |
| 2016 | | | | | | | | | | | | | |
| Fuel oils | Other current assets | $ | 2 |
| $ | — |
| $ | 2 |
| Other current assets | $ | 2 |
| $ | — |
| $ | 2 |
| |
| | Other assets | | 1 |
| | — |
| | 1 |
| Other assets | | 1 |
| | — |
| | 1 |
| |
| Natural gas | Other current assets | | 1 |
| | 11 |
| | 12 |
| Other current assets | | 1 |
| | 11 |
| | 12 |
| |
| | Other assets | | 1 |
| | 2 |
| | 3 |
| Other assets | | 1 |
| | 2 |
| | 3 |
| |
| Power | Other current assets | | 9 |
| | — |
| | 9 |
| Other current assets | | 9 |
| | — |
| | 9 |
| |
| | Total assets (a) | $ | 14 |
| $ | 13 |
| $ | 27 |
| Total assets (a) | $ | 14 |
| $ | 13 |
| $ | 27 |
| |
| Fuel oils | Other current liabilities | $ | 5 |
| $ | — |
| $ | 5 |
| Other current liabilities | $ | 5 |
| $ | — |
| $ | 5 |
| |
| Natural gas | MTM derivative liabilities | | (b) |
| | 3 |
| | (b) |
| Other current liabilities | | 1 |
| | 3 |
| | 4 |
| |
| | Other current liabilities | | 1 |
| | — |
| | 4 |
| Other deferred credits and liabilities | | 5 |
| | 5 |
| | 10 |
| |
| | Other deferred credits and liabilities | | 5 |
| | 5 |
| | 10 |
| |
| Power | MTM derivative liabilities | | (b) |
| | 12 |
| | (b) |
| Other current liabilities | | 3 |
| | 12 |
| | 15 |
| |
| | Other current liabilities | | 3 |
| | — |
| | 15 |
| |
| | Other deferred credits and liabilities | | — |
| | 173 |
| | 173 |
| Other deferred credits and liabilities | | — |
| | 173 |
| | 173 |
| |
| Uranium | Other deferred credits and liabilities | | 4 |
| | — |
| | 4 |
| Other deferred credits and liabilities | | 4 |
| | — |
| | 4 |
| |
| | Total liabilities (c) | $ | 18 |
| $ | 193 |
| $ | 211 |
| Total liabilities (c) | $ | 18 |
| $ | 193 |
| $ | 211 |
| |
| 2015 | | | | | | | |
| Natural gas | Other current assets | $ | — |
| | 1 |
| $ | 1 |
| |
| | Other assets | | 1 |
| | — |
| | 1 |
| |
| Power | Other current assets | | 16 |
| | — |
| | 16 |
| |
| | Total assets (a) | $ | 17 |
| $ | 1 |
| $ | 18 |
| |
| Fuel oils | Other current liabilities | $ | 22 |
| $ | — |
| $ | 22 |
| |
| | Other deferred credits and liabilities | | 7 |
| | — |
| | 7 |
| |
| Natural gas | MTM derivative liabilities | | (b) |
| | 32 |
| | (b) |
| |
| | Other current liabilities | | 6 |
| | — |
| | 38 |
| |
| | Other deferred credits and liabilities | | 8 |
| | 18 |
| | 26 |
| |
| Power | MTM derivative liabilities | | (b) |
| | 13 |
| | (b) |
| |
| | Other current liabilities | | — |
| | — |
| | 13 |
| |
| | Other deferred credits and liabilities | | — |
| | 157 |
| | 157 |
| |
| Uranium | Other current liabilities | | 1 |
| | — |
| | 1 |
| |
| | Total liabilities (c) | $ | 44 |
| $ | 220 |
| $ | 264 |
| |
| |
| (a) | The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability. |
| |
| (b) | Balance sheet line item not applicableBeginning 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 registrant.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. As of December 31, 2016 and 2015, Ameren Missouri's balance sheet reflected $12 million and $11 million, respectively, of cash collateral posted within "Other Assets." As of December 31, 2015, Ameren Illinois' balance sheet reflected $3 million of cash collateral posted within "Other Assets."
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 gross 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, 20162017 and 2015.
2016.
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 presentedcalculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. As of December 31, 2016,2017, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies'Companies’ maximum exposure 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 contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded, 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, 2016,2017, 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, 2016,2017, and (2) those counterparties with rights to do so requested collateral.
| | | | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| 2016 | | | | | | |
| 2017 | | | | | | |
| Ameren Missouri | $ | 64 |
| | $ | 3 |
| | $ | 54 |
| $ | 55 |
| | $ | 3 |
| | $ | 44 |
|
| Ameren Illinois | 33 |
| | — |
| | 26 |
| 43 |
| | — |
| | 38 |
|
| Ameren | $ | 97 |
| | $ | 3 |
| | $ | 80 |
| $ | 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: 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.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri'sMissouri’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: 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 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 derivatives 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: 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 escalation 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, 20162017 and 2015:2016:
| | | | | Fair Value | | Weighted | | Fair Value | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
Level 3 Derivative asset and liability – commodity contracts(a): | Level 3 Derivative asset and liability – commodity contracts(a): | | 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 | Fuel oils | $ | 1 |
| $ | — |
| | Option model | Volatilities(%)(b) | 24 – 66 | 28 |
| | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.13 – 0.22 | 0.15 | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.13 – 0.22 | 0.15 |
| | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | Escalation rate(%)(b)(f) | (2) – 2 | 0 | | | | Escalation rate(%)(b)(i) | (2) – 2 | 0 |
| | Natural Gas | 1 |
| (1 | ) | | Option model | Volatilities(%)(b) | 31 – 66 | 36 | Natural Gas | $ | 1 |
| $ | (1 | ) | | Option model | Volatilities(%)(b) | 31 – 66 | 36 |
| |
|
| |
| Nodal basis($/mmbtu)(b) | (0.40) – (0.10) | (0.20) | | | | Nodal basis($/mmbtu)(b) | (0.40) – (0.10) | (0.20) |
| |
|
| | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.80) – 0 | (0.50) | | | | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.80) – 0 | (0.50) |
| |
|
| |
| Counterparty credit risk(%)(c)(d) | 0.13 – 8 | 1 | | | | Counterparty credit risk(%)(c)(d) | 0.13 – 8 | 1 |
| |
|
| |
| Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | Power(g) | 9 |
| (187 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(h) | 26 – 44 | 29 | Power(f) | 9 |
| (187 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 26 – 44 | 29 |
| | | | | Estimated auction price for FTRs($/MW)(b) | (71) – 5,270 | 125 | | | | Estimated auction price for FTRs($/MW)(b) | (71) – 5,270 | 125 |
| | | | | Nodal basis($/MWh)(h) | (6) – 0 | (2) | | | | Nodal basis($/MWh)(g) | (6) – 0 | (2) |
| | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | Escalation rate(%)(b)(i) | 5 | (e) | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| | Uranium | — |
| (4 | ) | | Option model | Volatilities(%)(b) | 24 | (e) | Uranium | — |
| (4 | ) | | Option model | Volatilities(%)(b) | 24 | (e) |
| | | | | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 22 – 24 | 22 | |
| | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) | |
| 2015 | | | | |
| | Natural Gas | $ | 1 |
| $ | (1 | ) | | Option model | Volatilities(%)(b) | 35 – 55 | 45 | |
| | | | | Nodal basis($/mmbtu)(c) | (0.30) – 0 | (0.20) | |
| | | | | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.10) – 0 | (0.10) | |
| | | | | Counterparty credit risk(%)(c)(d) | 0.40 – 12 | 7 | |
| | | | | Ameren Missouri credit risk(%)(c)(d) | 0.40 | (e) | |
| | Power(g) | 16 |
| (170 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(h) | 22 – 39 | 29 | |
| | | | | Estimated auction price for FTRs($/MW)(b) | (270) – 2,057 | 211 | |
| | | | | Nodal basis($/MWh)(h) | (10) – (1) | (3) | |
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.86 | (e) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.40 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 4 |
| | | | | | | Escalation rate(%)(b)(i) | 3 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| | Uranium | — |
| (1 | ) | | Option model | Volatilities(%)(b) | 20 | (e) |
| | | | | | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 35 – 42 | 37 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.40 | (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) | Escalation rate applies to fuel oil prices 2019 and beyond. |
| |
(g) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2020.2021. Valuations beyond 20202021 use fundamentally modeled pricing by month for peak and off-peak demand. |
| |
(h)(g) | The balance at Ameren is comprised of Ameren Missouri and Ameren Illinois power contracts which respond differently to unobservable input changes because of their opposing positions. |
| |
(i)(h) | Escalation rate applies to power prices in 2031 and beyond for December 31, 2016, andbeyond. |
| |
| (i) | Escalation rate applies to powerfuel oil prices in 20262019 and beyond for December 31, 2015.beyond. |
We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and 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 gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in 2017, 2016, 2015 or 2014.2015. At December 31, 20162017 and 2015,2016, 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, 20162017:
| | | | | 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 | | | 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): | | | | | | | | | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| | Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Natural gas | | 2 |
| | 12 |
| | 1 |
| | 15 |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 12 |
| | $ | 11 |
| | $ | 27 |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | Equity securities: | | | | | | | | | | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | Debt securities: | | | | | | | | | | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | Total Ameren | | $ | 413 |
| | $ | 208 |
| | $ | 11 |
| | $ | 632 |
| | Total Ameren | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | | 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 | | | 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 | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Natural gas | | — |
| | 1 |
| | 1 |
| | 2 |
| | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| | Equity securities: | | | | | | | | | |
| | Total derivative assets – commodity contracts | | $ | 2 |
| | $ | 1 |
| | $ | 11 |
| | $ | 14 |
| | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | Debt securities: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Equity securities: | | | | | | | | | | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Debt securities: | | | | | | | | | | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| | Total Ameren Missouri | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| | 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): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| | |
| | Power | | — |
| | 1 |
| | 187 |
| | 188 |
| | Natural gas | | 1 |
| | 25 |
| | 4 |
| | 30 |
| |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| | Power | | — |
| | — |
| | 196 |
| | 196 |
| |
| | Total Ameren | | $ | 5 |
| | $ | 14 |
| | $ | 192 |
| | $ | 211 |
| | Total Ameren | | $ | 1 |
| | $ | 25 |
| | $ | 200 |
| | $ | 226 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | Natural gas | | — |
| | 7 |
| | 1 |
| | 8 |
| |
| | Natural gas | | — |
| | 6 |
| | — |
| | 6 |
| | Power | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | 1 |
| | 2 |
| | 3 |
| | Total Ameren Missouri | | $ | — |
| | $ | 7 |
| | $ | 2 |
| | $ | 9 |
| |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| | |
| | Total Ameren Missouri | | $ | 5 |
| | $ | 7 |
| | $ | 6 |
| | $ | 18 |
| | |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 7 |
| | $ | 1 |
| | $ | 8 |
| | Natural gas | | $ | 1 |
| | $ | 18 |
| | $ | 3 |
| | $ | 22 |
| |
| | Power | | — |
| | — |
| | 185 |
| | 185 |
| | Power | | — |
| | — |
| | 195 |
| | 195 |
| |
| | Total Ameren Illinois | | $ | — |
| | $ | 7 |
| | $ | 186 |
| | $ | 193 |
| | 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 million of receivables, payables, and accrued income, net. |
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, 20152016:
| | | | | 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 | | | 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): | | | | | | | | | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Power | | — |
| | — |
| | 16 |
| | 16 |
| | Natural gas | | 2 |
| | 12 |
| | 1 |
| | 15 |
| |
| | Total derivative assets – commodity contracts | | $ | — |
| | $ | 1 |
| | $ | 17 |
| | $ | 18 |
| | 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 | | | 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: | | | | | | | | | | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Equity securities: | | | | | | | | | | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 364 |
| | — |
| | — |
| | 364 |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | Debt securities: | | | | | | | | | | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 109 |
| | — |
| | 109 |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | Corporate bonds | | — |
| | 58 |
| | — |
| | 58 |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | Other | | — |
| | 22 |
| | — |
| | 22 |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | Total nuclear decommissioning trust fund | | $ | 368 |
| | $ | 189 |
| | $ | — |
| | $ | 557 |
| (b) | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | Total Ameren | | $ | 368 |
| | $ | 190 |
| | $ | 17 |
| | $ | 575 |
| | Total Ameren | | $ | 413 |
| | $ | 208 |
| | $ | 11 |
| | $ | 632 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Power | | — |
| | — |
| | 16 |
| | 16 |
| | Natural gas | | — |
| | 1 |
| | 1 |
| | 2 |
| |
| | Total derivative assets – commodity contracts | | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | 17 |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | Total derivative assets – commodity contracts | | $ | 2 |
| | $ | 1 |
| | $ | 11 |
| | $ | 14 |
| |
| | Cash and cash equivalents | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Equity securities: | | | | | | | | | | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | U.S. large capitalization | | 364 |
| | — |
| | — |
| | 364 |
| | Equity securities: | | | | | | | | | |
| | Debt securities: | | | | | | | | | | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | U.S. Treasury and agency securities | | — |
| | 109 |
| | — |
| | 109 |
| | Debt securities: | | | | | | | | | |
| | Corporate bonds | | — |
| | 58 |
| | — |
| | 58 |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | Other | | — |
| | 22 |
| | — |
| | 22 |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | Total nuclear decommissioning trust fund | | $ | 368 |
| | $ | 189 |
| | $ | — |
| | $ | 557 |
| (b) | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | Total Ameren Missouri | | $ | 368 |
| | $ | 189 |
| | $ | 17 |
| | $ | 574 |
| | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | | Total Ameren Missouri | | $ | 411 |
| | $ | 197 |
| | $ | 11 |
| | $ | 619 |
| |
| Ameren Illinois | Derivative assets – commodity contracts(a): | | | | | | | | | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | Natural gas | | $ | 2 |
| | $ | 11 |
| | $ | — |
| | $ | 13 |
| |
| Liabilities: | | | | | | | | | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | 1 |
| | 62 |
| | 1 |
| | 64 |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| |
| | Power | | — |
| | — |
| | 170 |
| | 170 |
| | Power | | — |
| | 1 |
| | 187 |
| | 188 |
| |
| | Uranium | | — |
| | — |
| | 1 |
| | 1 |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren | | $ | 30 |
| | $ | 62 |
| | $ | 172 |
| | $ | 264 |
| | Total Ameren | | $ | 5 |
| | $ | 14 |
| | $ | 192 |
| | $ | 211 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| | Natural gas | | — |
| | 6 |
| | — |
| | 6 |
| |
| | Uranium | | — |
| | — |
| | 1 |
| | 1 |
| | Power | | — |
| | 1 |
| | 2 |
| | 3 |
| |
| | Total Ameren Missouri | | $ | 29 |
| | $ | 13 |
| | $ | 2 |
| | $ | 44 |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | | Total Ameren Missouri | | $ | 5 |
| | $ | 7 |
| | $ | 6 |
| | $ | 18 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | 1 |
| | $ | 49 |
| | $ | — |
| | $ | 50 |
| | Natural gas | | $ | — |
| | $ | 7 |
| | $ | 1 |
| | $ | 8 |
| |
| | Power | | — |
| | — |
| | 170 |
| | 170 |
| | Power | | — |
| | — |
| | 185 |
| | 185 |
| |
| | Total Ameren Illinois | | $ | 1 |
| | $ | 49 |
| | $ | 170 |
| | $ | 220 |
| | Total Ameren Illinois | | $ | — |
| | $ | 7 |
| | $ | 186 |
| | $ | 193 |
| |
| |
| (a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
| (b) | Balance excludes $(1)$2 million of receivables, payables, and accrued income, net. |
All costs related to financial assets and liabilities including those classified as Level 3 in the fair value hierarchy are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. For the years ended December 31, 20162017 and 2015,2016, the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils, natural gas, and uranium were immaterial.
The following table summarizes the changes in the fair value of power financial assets and liabilities classified as Level 3 in the fair value hierarchy:
| | | | | Net Derivative Commodity Contracts | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren |
| For the year ended December 31, 2015 | | | | | | | |
| Beginning balance at January 1, 2015 | $ | 9 |
| $ | (142 | ) | $ | (133 | ) | |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities: | | 2 |
| | (41 | ) | | (39 | ) | |
| Purchases | | 29 |
| | — |
| | 29 |
| |
| Settlements | | (23 | ) | | 13 |
| | (10 | ) | |
| Transfers out of Level 3 | | (1 | ) | | — |
| | (1 | ) | |
| Ending balance at December 31, 2015 | $ | 16 |
| $ | (170 | ) | $ | (154 | ) | |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2015 | $ | — |
| $ | (39 | ) | $ | (39 | ) | |
| For the year ended December 31, 2016 | | | | | | | | | | | | |
| Beginning balance at January 1, 2016 | $ | 16 |
| $ | (170 | ) | $ | (154 | ) | $ | 16 |
| $ | (170 | ) | $ | (154 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities: | | (1 | ) | | (29 | ) | | (30 | ) | |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | | (1 | ) | | (29 | ) | | (30 | ) |
| Purchases | | 13 |
| | — |
| | 13 |
| | 13 |
| | — |
| | 13 |
|
| Settlements | | (21 | ) | | 14 |
| | (7 | ) | | (21 | ) | | 14 |
| | (7 | ) |
| Ending balance at December 31, 2016 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2016 | $ | — |
| $ | (27 | ) | $ | (27 | ) | $ | — |
| $ | (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, 20162017 and 2015,2016, 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 1110 – Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 20162017, as well as a table summarizing the changes in Level 3 plan assets during 20162017.
The Ameren Companies’ carrying amounts of cash 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'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, 20162017 and 20152016:
| | | | 2016 | | 2015 | 2017 | | 2016 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Ameren:(a) | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations (including current portion) | $ | 7,276 |
| | $ | 7,772 |
| | $ | 7,275 |
| | $ | 7,814 |
| $ | 7,935 |
| | $ | 8,531 |
| | $ | 7,276 |
| | $ | 7,772 |
|
| Preferred stock | 142 |
| | 131 |
| | 142 |
| | 125 |
| |
Preferred stock(b) | | 142 |
| | 131 |
| | 142 |
| | 131 |
|
| Ameren Missouri: | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations (including current portion) | $ | 3,994 |
| | $ | 4,304 |
| | $ | 4,110 |
| | $ | 4,449 |
| $ | 3,961 |
| | $ | 4,348 |
| | $ | 3,994 |
| | $ | 4,304 |
|
| Preferred stock | 80 |
| | 79 |
| | 80 |
| | 75 |
| 80 |
| | 80 |
| | 80 |
| | 79 |
|
| Ameren Illinois: | | | | | | | | | | | | | | |
| Long-term debt (including current portion) | $ | 2,588 |
| | $ | 2,765 |
| | $ | 2,471 |
| | $ | 2,665 |
| $ | 2,830 |
| | $ | 3,028 |
| | $ | 2,588 |
| | $ | 2,765 |
|
| Preferred stock | 62 |
| | 52 |
| | 62 |
| | 50 |
| 62 |
| | 51 |
| | 62 |
| | 52 |
|
| |
| (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, classified as held-to-maturity and recorded in “Other Assets” that are related to the capital lease obligation CTs from the city of Bowling Green and Audrain County. As of December 31, 2017 and 2016, the fair value of these investments approximate carrying value of $276 million and $282 million, respectively. |
| |
| (b) | Preferred stock is recorded in "Noncontrolling Interests"“Noncontrolling Interests” on the consolidated balance sheet. |
NOTE 9 – NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
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. We have classified these investments as available for sale, and we have recorded all such
investments at their fair market value at December 31, 2016, and 2015. See Note 10 – Callaway Energy Center for additional information.
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, 2016, 2015, and 2014:
|
| | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| Proceeds from sales and maturities | $ | 377 |
| | $ | 349 |
| | $ | 391 |
|
| Gross realized gains | 7 |
| | 8 |
| | 7 |
|
| Gross realized losses | 4 |
| | 2 |
| | 2 |
|
Net realized and unrealized gains and losses are deferred and are currently recorded as a 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.
The following table presents the costs and fair values of investments in debt and equity securities in Ameren's and Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2016 and 2015:
|
| | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2016 | | | | | | | |
| Debt securities | $ | 197 |
| | $ | 3 |
| $ | 4 |
| | $ | 196 |
|
| Equity securities | 161 |
| | 253 |
| | 6 |
| | 408 |
|
| Cash | 1 |
| | — |
| | — |
| | 1 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 361 |
| | $ | 256 |
| $ | 10 |
| | $ | 607 |
|
| 2015 | | | | | | | |
| Debt securities | $ | 191 |
| | $ | 2 |
| $ | 4 |
| | $ | 189 |
|
| Equity securities | 147 |
| | 224 |
| | 7 |
| | 364 |
|
| Cash | 4 |
| | — |
| | — |
| | 4 |
|
Other(a) | (1 | ) | | — |
| | — |
| | (1 | ) |
| Total | $ | 341 |
| | $ | 226 |
| $ | 11 |
| | $ | 556 |
|
| |
(a) | Represents net receivables and payables relating to pending security sales, interest, and security 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, 2016:
|
| | | | | | | |
| | Cost | | Fair Value |
| Less than 5 years | $ | 105 |
| | $ | 104 |
|
| 5 years to 10 years | 47 |
| | 47 |
|
| Due after 10 years | 45 |
| | 45 |
|
| Total | $ | 197 |
| | $ | 196 |
|
We have unrealized losses relating to certain available-for-sale investments included in our nuclear decommissioning trust fund, recorded as a regulatory asset as discussed above. Decommissioning will not occur until our nuclear energy center is retired. The Callaway energy center’s current operating license expires in 2044.
NOTE 109 – CALLAWAY ENERGY CENTER
Spent Nuclear Fuel
Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. UnderThe NWPA established the NWPA,fee paid by Ameren Missouri and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities payto the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth(one-tenth of one cent,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, Ameren Missouri and other utilities have entered into standard contracts with the DOE. Consistent with the NWPA and its standard contract, 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. Because the federal government is not meeting its disposal obligation, the collection of this fee was suspended in May 2014. The DOE'sDOE’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'sDOE’s failure to fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. The lawsuit 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 $3 million, $24 million, and $14 million in 2017, 2016, and $15 million in 2016, 2015, and 2014, respectively. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.
Supplier of Fuel Assemblies
The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse, which is the only NRC-licensed 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. 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.
Decommissioning
Electric utility rates charged to customers provide for the recovery of the Callaway energy center'scenter’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’s decommissioning. It is assumed that the Callaway energy center site will be eventually decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy 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'sMissouri’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. An updated cost study and funding analysis was filed with the MoPSC in September 2017 and reflected within the ARO. In April 2016,January 2018, the MoPSC approved no change in electric service rates for decommissioning costs.costs based on Ameren Missouri’s updated cost study and funding analysis.
The fair value of the trust fund for Ameren Missouri'sMissouri’s Callaway energy center is reported as "Nuclear“Nuclear decommissioning trust fund"fund” in Ameren'sAmeren’s and Ameren Missouri'sMissouri’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 such earnings deficiency will be recovered in 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. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 2017 and 2016. 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, and 2015:
|
| | | | | | | | | | | |
| | 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 MattersMatters.
The following table presents the costs and Note 9 – Nuclearfair values of investments in debt and equity securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2017 and 2016:
|
| | | | | | | | | | | | | | |
| 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 security sales, interest, and security 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, 2017:
|
| | | | | | | |
| | 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 Trust Fund Investmentswill not occur until Ameren Missouri’s nuclear 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 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.
|
| | | | | | | | |
| 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. |
| |
| (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 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 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 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 additional
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. 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 are subject to industrywide aggregates. 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 full 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. The EMANI policies have an aggregate limit of €600 million for radiation and nonradiation events within a period of 72 hours.
information related toIf losses from a nuclear incident at the Callaway energy center.center exceed the insurance limits, 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 1110 – 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. 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 $774$551 million and $567$774 million as of December 31, 20162017, and December 31, 2015,2016, respectively. These net liabilities are recorded in "Other“Other current liabilities," "Pensionliabilities” and “Pension and other postretirement benefits," and "Other assets"benefits” on Ameren'sAmeren’s consolidated balance sheet. The primary factor contributing to the increasedecrease in the unfunded obligation during 20162017 was the result of a larger-than-expected increase in the return on plan assets of the pension and postretirement trusts, offset by a 50 basis point decrease in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligation. The increasedecrease in the unfunded obligation also resulted in an increasea decrease to "Regulatory assets"“Regulatory assets” on Ameren's,Ameren’s, Ameren Missouri's,Missouri’s, and Ameren Illinois' consolidatedIllinois’ balance sheet.sheets.
The following table presents the net benefit liability recorded on the balance sheets of each of the Ameren Companies as of December 31, 20162017 and 20152016:
| | | | 2016 |
| 2015 |
| 2017 |
| 2016 |
|
Ameren(a) | $ | 774 |
| $ | 567 |
| $ | 551 |
| $ | 774 |
|
| Ameren Missouri | 293 |
| 236 |
| 215 |
| 293 |
|
Ameren Illinois | 315 |
| 219 |
| 213 |
| 315 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (b) | Other postretirement benefit liability is 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'sAmeren’s pension and postretirement benefit plans as of December 31, 20162017 and 20152016. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 20162017 and 20152016, that have not been recognized in net periodic benefit costs.
| | | | 2016 | | 2015 | 2017 | | 2016 |
| | Pension Benefits(a) | | Postretirement Benefits(a) | | Pension Benefits(a) | | Postretirement Benefits(a) | Pension Benefits(a) | | Postretirement Benefits(a) | | Pension Benefits(a) | | Postretirement Benefits(a) |
| Accumulated benefit obligation at end of year | $ | 4,288 |
| $ | (b) |
| | $ | 3,995 |
| $ | (b) |
| $ | 4,577 |
| $ | (b) |
| | $ | 4,288 |
| $ | (b) |
|
| Change in benefit obligation: | | | | | | | | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,197 |
| $ | 1,094 |
| | $ | 4,410 |
| $ | 1,203 |
| $ | 4,518 |
| $ | 1,170 |
| | $ | 4,197 |
| $ | 1,094 |
|
| Service cost | 81 |
| | 19 |
| | 92 |
| | 24 |
| 93 |
| | 21 |
| | 81 |
| | 19 |
|
| Interest cost | 185 |
| | 50 |
| | 174 |
| | 48 |
| 179 |
| | 47 |
| | 185 |
| | 50 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 8 |
| — |
| | 8 |
| | — |
| | 8 |
|
| Actuarial (gain) loss | 265 |
| | 52 |
| | (256 | ) | | (133 | ) | |
| Settlement | — |
| | — |
| | (2 | ) | | — |
| |
| Actuarial loss | | 255 |
| | 53 |
| | 265 |
| | 52 |
|
| Benefits paid | (210 | ) | | (54 | ) | | (221 | ) | | (56 | ) | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Federal subsidy on benefits paid | (b) |
| | 1 |
| | (b) |
| | — |
| (b) |
| | — |
| | (b) |
| | 1 |
|
| Net benefit obligation at end of year | 4,518 |
| | 1,170 |
| | 4,197 |
| | 1,094 |
| 4,827 |
| | 1,240 |
| | 4,518 |
| | 1,170 |
|
| Change in plan assets: | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | 3,653 |
| | 1,071 |
| | 3,794 |
| | 1,109 |
| 3,813 |
| | 1,101 |
| | 3,653 |
| | 1,071 |
|
| Actual return on plan assets | 313 |
| | 73 |
| | (29 | ) | | (8 | ) | 634 |
| | 171 |
| | 313 |
| | 73 |
|
| Employer contributions | 57 |
| | 2 |
| | 111 |
| | 18 |
| 64 |
| | 2 |
| | 57 |
| | 2 |
|
| Federal subsidy on benefits paid | (b) |
| | 1 |
| | (b) |
| | — |
| (b) |
| | — |
| | (b) |
| | 1 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 8 |
| — |
| | 8 |
| | — |
| | 8 |
|
| Settlements | — |
| | — |
| | (2 | ) | | — |
| |
| Benefits paid | (210 | ) | | (54 | ) | | (221 | ) | | (56 | ) | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Fair value of plan assets at end of year | 3,813 |
| | 1,101 |
| | 3,653 |
| | 1,071 |
| 4,293 |
| | 1,223 |
| | 3,813 |
| | 1,101 |
|
| Funded status – deficiency | 705 |
| | 69 |
| | 544 |
| | 23 |
| 534 |
| | 17 |
| | 705 |
| | 69 |
|
| Accrued benefit cost at December 31 | $ | 705 |
| $ | 69 |
| | $ | 544 |
| $ | 23 |
| $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in the balance sheet consist of: | | | | | | | | | | | | | | |
Noncurrent asset(c) | $ | — |
| $ | — |
| | $ | — |
| $ | (18 | ) | |
Current liability(d) | 3 |
| | 2 |
| | 3 |
| | 2 |
| |
Current liability(c) | | 3 |
| | 3 |
| | 3 |
| | 2 |
|
| Noncurrent liability | 702 |
| | 67 |
| | 541 |
| | 39 |
| 531 |
| | 14 |
| | 702 |
| | 67 |
|
| Net liability recognized | $ | 705 |
| $ | 69 |
| | $ | 544 |
| $ | 23 |
| $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in regulatory assets consist of: | | | | | | | | | | | | | | |
| Net actuarial (gain) loss | $ | 535 |
| $ | (29 | ) | | $ | 395 |
| $ | (82 | ) | $ | 374 |
| $ | (69 | ) | | $ | 535 |
| $ | (29 | ) |
| Prior service cost (credit) | (4 | ) | | (8 | ) | | (5 | ) | | (11 | ) | |
| Prior service credit | | (3 | ) | | (3 | ) | | (4 | ) | | (8 | ) |
| Amounts (pretax) recognized in accumulated OCI consist of: | | | | | | | | | | | | | | |
| Net actuarial (gain) loss | 43 |
| | — |
| | 17 |
| | (3 | ) | |
| Prior service cost (credit) | — |
| | (1 | ) | | — |
| | — |
| |
| Net actuarial loss | | 30 |
| | 2 |
| | 43 |
| | — |
|
| Prior service credit | | — |
| | — |
| | — |
| | (1 | ) |
| Total | $ | 574 |
| $ | (38 | ) | | $ | 407 |
| $ | (96 | ) | $ | 401 |
| $ | (70 | ) | | $ | 574 |
| $ | (38 | ) |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (c) | Included in "Other assets"“Other current liabilities” on Ameren's consolidated balance sheet. |
| |
(d) | Included in "Other current liabilities" on Ameren'sAmeren’s consolidated balance sheet. |
The following table presents the assumptions used to determine our benefit obligations at December 31, 20162017 and 20152016:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| Discount rate at measurement date | 4.00 | % | | 4.50 | % | | 4.00 | % | | 4.50 | % | 3.50 | % | | 4.00 | % | | 3.50 | % | | 4.00 | % |
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial) | (a) |
| | (a) |
| | 5.00 |
| | 5.00 |
| (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate) | (a) |
| | (a) |
| | 5.00 |
| | 5.00 |
| (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
| |
| (a) | Not applicableInitial 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'splan’s projected benefit payments. The settlement portfolio of bonds is selected from a pool of more than 700600 high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan'splan’s benefit payments that equates to the market value of the selected bonds. In addition, during 2016,2017, Ameren adopted the Society of Actuaries 2016 Mortality Tables Report and2017 Mortality Improvement Scale. The updated mortality tables assumescale assumes a lower rate of mortality improvement as compared to the 2015 Mortality Tables Report and2016 Mortality Improvement Scale that Ameren adopted
used in 2015. The 2016, tables lowered projected improvements in life expectancies for our employees and retirees, resulting 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. Considering its assumptions at December 31, 20162017, its investment performance in 2016,2017, and its pension funding policy, Ameren expects to make annual contributions of less than $501 million to $7060 million in each of the next five years, with aggregate estimated contributions of $290120 million. We expect Ameren Missouri’sMissouri and Ameren Illinois’Illinois expect their portion of the future funding requirements to be 35% and 55%, respectively. These amounts are estimates. They 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 20162017, 20152016, and 20142015:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 21 |
| | $ | 47 |
| | $ | 41 |
| | $ | 1 |
| | $ | 8 |
| | $ | 3 |
| $ | 19 |
| | $ | 21 |
| | $ | 47 |
| | $ | 1 |
| | $ | 1 |
| | $ | 8 |
|
| Ameren Illinois | 30 |
| | 45 |
| | 39 |
| | 1 |
| | 8 |
| | 2 |
| 37 |
| | 30 |
| | 45 |
| | 1 |
| | 1 |
| | 8 |
|
| Other | 6 |
| | 19 |
| | 19 |
| | — |
| | 2 |
| | 1 |
| 8 |
| | 6 |
| | 19 |
| | — |
| | — |
| | 2 |
|
| Ameren | 57 |
| | 111 |
| | 99 |
| | 2 |
| | 18 |
| | 6 |
| 64 |
| | 57 |
| | 111 |
| | 2 |
| | 2 |
| | 18 |
|
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 2017.2018. No plan assets are expected to be returned to Ameren during 2017.2018.
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 20172018 and our pension and postretirement plans’ asset categories as of December 31, 20162017 and 20152016:
| | Asset Category | Target Allocation 2017 | | Percentage of Plan Assets at December 31, | Target Allocation 2018 | | Percentage of Plan Assets at December 31, |
| 2016 | | 2015 | 2017 | | 2016 |
| Pension Plan: | | | | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 1 | % | 0% – 5% | | 1 | % | | 1 | % |
| Equity securities: | | | | | | | | |
| U.S. large-capitalization | 29% – 39% | | 34 | % | | 34 | % | 29% – 39% | | 34 | % | | 34 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 7 | % | 3% – 13% | | 9 | % | | 9 | % |
| International and emerging markets | 9% – 19% | | 14 | % | | 13 | % | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 51% – 61% | | 57 | % | | 54 | % | 51% – 61% | | 57 | % | | 57 | % |
| Debt securities | 35% – 45% | | 37 | % | | 40 | % | 35% – 45% | | 37 | % | | 37 | % |
| Real estate | 0% – 9% | | 5 | % | | 5 | % | 0% – 9% | | 5 | % | | 5 | % |
| Private equity | 0% – 5% | | (a) |
| | (a) |
| 0% – 5% | | (a) |
| | (a) |
|
| Total | | | 100 | % | | 100 | % | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | | | | |
| Cash and cash equivalents | 0% – 7% | | 3 | % | | 4 | % | 0% – 7% | | 2 | % | | 3 | % |
| Equity securities: | | | | | | | | |
| U.S. large-capitalization | 34% – 44% | | 40 | % | | 39 | % | 34% – 44% | | 41 | % | | 40 | % |
| U.S. small- and mid-capitalization | 2% – 12% | | 7 | % | | 7 | % | 2% – 12% | | 8 | % | | 7 | % |
| International | 9% – 19% | | 14 | % | | 13 | % | |
| International and emerging markets | | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 55% – 65% | | 61 | % | | 59 | % | 55% – 65% | | 63 | % | | 61 | % |
| Debt securities | 33% – 43% | | 36 | % | | 37 | % | 33% – 43% | | 35 | % | | 36 | % |
| Total | | | 100 | % | | 100 | % | | | 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, 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, exchange traded funds, 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, 20162017. 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 on or before the measurementthat date. Securities traded in over-the-counter markets are valued based onby 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 areis based on NAVNAV; 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'sfund’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 planplans’ assets measured at fair value as of December 31, 20162017:
| | | | 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(a) | | Total | 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 | $ | — |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | 25 |
|
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,352 |
| | 1,352 |
| — |
| | — |
| | — |
| | 1,523 |
| | 1,523 |
|
| U.S. small- and mid-capitalization | 361 |
| | — |
| | — |
| | — |
| | 361 |
| 379 |
| | — |
| | — |
| | — |
| | 379 |
|
| International and emerging markets | 133 |
| | — |
| | — |
| | 389 |
| | 522 |
| 179 |
| | — |
| | — |
| | 450 |
| | 629 |
|
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 617 |
| | — |
| | 13 |
| | 630 |
| — |
| | 726 |
| | — |
| | 15 |
| | 741 |
|
| Municipal bonds | — |
| | 95 |
| | — |
| | — |
| | 95 |
| — |
| | 91 |
| | — |
| | — |
| | 91 |
|
| U.S. Treasury and agency securities | — |
| | 701 |
| | — |
| | — |
| | 701 |
| 8 |
| | 816 |
| | — |
| | — |
| | 824 |
|
| Other | — |
| | 21 |
| | — |
| | — |
| | 21 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Real estate | — |
| | — |
| | — |
| | 202 |
| | 202 |
| — |
| | — |
| | — |
| | 196 |
| | 196 |
|
| Private equity | — |
| | — |
| | — |
| | 6 |
| | 6 |
| — |
| | — |
| | — |
| | 4 |
| | 4 |
|
| Total | $ | 494 |
| | $ | 1,434 |
| | $ | — |
| | $ | 1,995 |
| | $ | 3,923 |
| $ | 566 |
| | $ | 1,640 |
| | $ | — |
| | $ | 2,213 |
| | $ | 4,419 |
|
Less: Medical benefit assets at December 31(b)(a) | | | | | | | | | (132 | ) | | | | | | | | | (153 | ) |
Plus: Net receivables at December 31(c)(b) | | | | | | | | | 22 |
| | | | | | | | | 27 |
|
| Fair value of pension plans assets at year end | | | | | | | | | $ | 3,813 |
| |
| Fair value of pension plans’ assets at December 31 | | | | | | | | | | $ | 4,293 |
|
| |
| (a) | Reflects the adoption of the new authoritative accounting guidance related to investments measured at the NAV practical expedient. See Note 1 - Summary of Significant Accounting Policies for additional information. |
| |
(b) | 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. |
| |
(c)(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 pension planplans’ assets measured at fair value as of December 31, 20152016:
| | | | 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(a) | | Total | 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 |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | 20 |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
|
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,296 |
| | 1,296 |
| — |
| | — |
| | — |
| | 1,352 |
| | 1,352 |
|
| U.S. small- and mid-capitalization | 268 |
| | — |
| | — |
| | — |
| | 268 |
| 361 |
| | — |
| | — |
| | — |
| | 361 |
|
| International and emerging markets | 122 |
| | 126 |
| | — |
| | 243 |
| | 491 |
| 133 |
| | — |
| | — |
| | 389 |
| | 522 |
|
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 617 |
| | — |
| | 14 |
| | 631 |
| — |
| | 617 |
| | — |
| | 13 |
| | 630 |
|
| Municipal bonds | — |
| | 104 |
| | — |
| | — |
| | 104 |
| — |
| | 95 |
| | — |
| | — |
| | 95 |
|
| U.S. Treasury and agency securities | 6 |
| | 751 |
| | — |
| | — |
| | 757 |
| — |
| | 701 |
| | — |
| | — |
| | 701 |
|
| Other | — |
| | 5 |
| | — |
| | — |
| | 5 |
| — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Real estate | — |
| | — |
| | — |
| | 168 |
| | 168 |
| — |
| | — |
| | — |
| | 202 |
| | 202 |
|
| Private equity | — |
| | — |
| | — |
| | 8 |
| | 8 |
| — |
| | — |
| | — |
| | 6 |
| | 6 |
|
| Total | $ | 396 |
| | $ | 1,603 |
| | $ | — |
| | $ | 1,749 |
| | $ | 3,748 |
| $ | 494 |
| | $ | 1,434 |
| | $ | — |
| | $ | 1,995 |
| | $ | 3,923 |
|
Less: Medical benefit assets at December 31(b)(a) | | | | | | | | | (123 | ) | | | | | | | | | (132 | ) |
Plus: Net receivables at December 31(c)(b) | | | | | | | | | 28 |
| | | | | | | | | 22 |
|
| Fair value of pension plans assets at year end | | | | | | | | | $ | 3,653 |
| |
| Fair value of pension plans’ assets at December 31 | | | �� | | | | | | | $ | 3,813 |
|
| |
| (a) | Reflects the adoption of the new authoritative accounting guidance related to investments measured at the NAV practical expedient. See Note 1 - Summary of Significant Accounting Policies for additional information. |
| |
(b) | 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. |
| |
(c)(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 plansplans’ assets measured at fair value as of December 31, 20162017:
| | | | 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(a) | | Total | 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 |
| $ | 44 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 44 |
|
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 291 |
| | — |
| | — |
| | 101 |
| | 392 |
| 332 |
| | — |
| | — |
| | 110 |
| | 442 |
|
| U.S. small- and mid-capitalization | 72 |
| | — |
| | — |
| | — |
| | 72 |
| 80 |
| | — |
| | — |
| | — |
| | 80 |
|
| International | 40 |
| | — |
| | — |
| | 92 |
| | 132 |
| |
| International and emerging markets | | 53 |
| | — |
| | — |
| | 101 |
| | 154 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
| — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 141 |
| | — |
| | — |
| | 141 |
| — |
| | 144 |
| | — |
| | — |
| | 144 |
|
| Municipal bonds | — |
| | 110 |
| | — |
| | — |
| | 110 |
| — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 68 |
| | — |
| | — |
| | 68 |
| — |
| | 76 |
| | — |
| | — |
| | 76 |
|
| Other | — |
| | — |
| | — |
| | 19 |
| | 19 |
| — |
| | 4 |
| | — |
| | 34 |
| | 38 |
|
| Total | $ | 456 |
| | $ | 326 |
| | $ | — |
| | $ | 212 |
| | $ | 994 |
| $ | 509 |
| | $ | 342 |
| | $ | — |
| | $ | 245 |
| | $ | 1,096 |
|
Plus: Medical benefit assets at December 31(b)(a) | | | | | | | | | 132 |
| | | | | | | | | 153 |
|
Less: Net payables at December 31(c)(b) | | | | | | | | | (25 | ) | | | | | | | | | (26 | ) |
| Fair value of postretirement benefit plans assets at year end | | | | | | | | | $ | 1,101 |
| |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | | $ | 1,223 |
|
| |
| (a) | Reflects the adoption of the new authoritative accounting guidance related to investments measured at the NAV practical expedient. See Note 1 - Summary of Significant Accounting Policies for additional information. |
| |
(b) | 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. |
| |
(c)(b) | Payables related to pending security 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 plansplans’ assets measured at fair value as of December 31, 20152016:
| | | | 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(a) | | Total | 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 | $ | 61 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 61 |
| $ | 53 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53 |
|
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 272 |
| | — |
| | — |
| | 98 |
| | 370 |
| 291 |
| | — |
| | — |
| | 101 |
| | 392 |
|
| U.S. small- and mid-capitalization | 65 |
| | — |
| | — |
| | — |
| | 65 |
| 72 |
| | — |
| | — |
| | — |
| | 72 |
|
| International | 33 |
| | 38 |
| | — |
| | 55 |
| | 126 |
| |
| International and emerging markets | | 40 |
| | — |
| | — |
| | 92 |
| | 132 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 138 |
| | — |
| | — |
| | 138 |
| — |
| | 141 |
| | — |
| | — |
| | 141 |
|
| Municipal bonds | — |
| | 114 |
| | — |
| | — |
| | 114 |
| — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 55 |
| | — |
| | — |
| | 55 |
| — |
| | 68 |
| | — |
| | — |
| | 68 |
|
| Other | — |
| | 4 |
| | — |
| | 36 |
| | 40 |
| — |
| | — |
| | — |
| | 19 |
| | 19 |
|
| Total | $ | 431 |
| | $ | 356 |
| | $ | — |
| | $ | 189 |
| | $ | 976 |
| $ | 456 |
| | $ | 326 |
| | $ | — |
| | $ | 212 |
| | $ | 994 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | | | 123 |
| | | | | | | | | 132 |
|
Less: Net payables at December 31(b) | | | | | | | | | (28 | ) | | | | | | | | | (25 | ) |
| Fair value of postretirement benefit plans assets at year end | | | | | | | | | $ | 1,071 |
| |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | | $ | 1,101 |
|
| |
| (a) | Reflects the adoption of the new authoritative accounting guidance related to investments measured at the NAV practical expedient. See Note 1 - Summary of Significant Accounting Policies for additional information. |
| |
(b) | 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. |
| |
(c)(b) | Payables related to pending security purchases, offset by Medicare, interest receivables and receivables related to pending security sales. |
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of Ameren'sAmeren’s pension and postretirement benefit plans during 20162017, 20152016, and 20142015:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| 2017 | | | | |
| Service cost | | $ | 93 |
| | $ | 21 |
|
| Interest cost | | 179 |
| | 47 |
|
| Expected return on plan assets | | (262 | ) | | (75 | ) |
| Amortization of: | | | | |
| Prior service credit | | (1 | ) | | (5 | ) |
| Actuarial (gain) loss | | 55 |
| | (6 | ) |
| Net periodic benefit cost (income) | | $ | 64 |
| | $ | (18 | ) |
| 2016 | | | | | | |
| Service cost | $ | 81 |
| | $ | 19 |
| $ | 81 |
| | $ | 19 |
|
| Interest cost | 185 |
| | 50 |
| 185 |
| | 50 |
|
| Expected return on plan assets | (253 | ) | | (72 | ) | (253 | ) | | (72 | ) |
| Amortization of: | | | | | | |
| Prior service credit | (1 | ) | | (5 | ) | (1 | ) | | (5 | ) |
| Actuarial (gain) loss | 32 |
| | (11 | ) | 32 |
| | (11 | ) |
| Net periodic benefit cost (benefit) | $ | 44 |
| | $ | (19 | ) | |
| Net periodic benefit cost (income) | | $ | 44 |
| | $ | (19 | ) |
| 2015 | | | | | | |
| Service cost | $ | 92 |
| | $ | 24 |
| $ | 92 |
| | $ | 24 |
|
| Interest cost | 174 |
| | 48 |
| 174 |
| | 48 |
|
| Expected return on plan assets | (248 | ) | | (68 | ) | (248 | ) | | (68 | ) |
| Amortization of: | | | | | | |
| Prior service credit | (1 | ) | | (5 | ) | (1 | ) | | (5 | ) |
| Actuarial loss | 74 |
| | 5 |
| 74 |
| | 5 |
|
| Settlement loss | 1 |
| | — |
| |
| Net periodic benefit cost (benefit) | $ | 92 |
| | $ | 4 |
| |
| 2014 | | | | |
| Service cost | $ | 79 |
| | $ | 19 |
| |
| Interest cost | 183 |
| | 50 |
| |
| Expected return on plan assets | (229 | ) | | (65 | ) | |
| Amortization of: | | | | |
| Prior service credit | (1 | ) | | (5 | ) | |
| Actuarial (gain) loss | 49 |
| | (7 | ) | |
| Net periodic benefit cost (benefit) | $ | 81 |
| | $ | (8 | ) | |
| Curtailment gain | | 1 |
| | — |
|
| Net periodic benefit cost | | $ | 92 |
| | $ | 4 |
|
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into Ameren'sAmeren’s net periodic benefit cost in 20172018 are as follows:
| | | Pension Benefits(a) | | Postretirement Benefits(a) | Pension Benefits(a) | | Postretirement Benefits(a) |
| Regulatory assets: | | | | | | |
| Prior service credit | $ | (1 | ) | | $ | (5 | ) | $ | (1 | ) | | $ | (2 | ) |
| Net actuarial (gain) loss | 50 |
| | (7 | ) | 60 |
| | (1 | ) |
| Accumulated OCI: | | | | | | |
| Net actuarial loss | 4 |
| | — |
| 5 |
| | — |
|
| Total | $ | 53 |
| | $ | (12 | ) | $ | 64 |
| | $ | (3 | ) |
| |
| (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 and included in continuing operations for the years ended December 31, 20162017, 20152016, and 20142015:
| | | | Pension Costs | | Postretirement Costs | Pension Costs | | Postretirement Costs |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Ameren Missouri(a) | $ | 26 |
| | $ | 54 |
| | $ | 50 |
| | $ | (5 | ) | | $ | 8 |
| | $ | 3 |
| $ | 24 |
| | $ | 26 |
| | $ | 54 |
| | $ | (4 | ) | | $ | (5 | ) | | $ | 8 |
|
| Ameren Illinois | 22 |
| | 38 |
| | 30 |
| | (13 | ) | | (3 | ) | | (9 | ) | 41 |
| | 22 |
| | 38 |
| | (14 | ) | | (13 | ) | | (3 | ) |
| Other | (4 | ) | | — |
| | 1 |
| | (1 | ) | | (1 | ) | | (2 | ) | (1 | ) | | (4 | ) | | — |
| | — |
| | (1 | ) | | (1 | ) |
| Ameren | 44 |
| | 92 |
| | 81 |
| | (19 | ) | | 4 |
| | (8 | ) | 64 |
| | 44 |
| | 92 |
| | (18 | ) | | (19 | ) | | 4 |
|
| |
| (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 under GAAP 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, 20162017, are as follows:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | Paid from Qualified Trust Funds | | Paid from Company Funds | | Paid from Qualified Trust Funds | | Paid from Company Funds | Paid from Qualified Trust Funds | | Paid from Company Funds | | Paid from Qualified Trust Funds | | Paid from Company Funds |
| 2017 | $ | 248 |
| | $ | 3 |
| | $ | 54 |
| | $ | 2 |
| |
| 2018 | 254 |
| | 3 |
| | 57 |
| | 2 |
| $ | 255 |
| | $ | 3 |
| | $ | 57 |
| | $ | 2 |
|
| 2019 | 261 |
| | 3 |
| | 59 |
| | 2 |
| 261 |
| | 3 |
| | 59 |
| | 2 |
|
| 2020 | 265 |
| | 3 |
| | 61 |
| | 2 |
| 266 |
| | 3 |
| | 62 |
| | 2 |
|
| 2021 | 273 |
| | 3 |
| | 63 |
| | 2 |
| 277 |
| | 3 |
| | 64 |
| | 2 |
|
2022 – 2026 | 1,405 |
| | 13 |
| | 331 |
| | 12 |
| |
| 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, 20162017, 20152016, and 20142015:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount rate at measurement date | 4.50 | % | | 4.00 | % | | 4.75 | % | | 4.50 | % | | 4.00 | % | | 4.75 | % | 4.00 | % | | 4.50 | % | | 4.00 | % | | 4.00 | % | | 4.50 | % | | 4.00 | % |
| Expected return on plan assets | 7.00 |
| | 7.25 |
| | 7.25 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
| 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 |
| 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial) | (a) |
| | (a) |
| | (a) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
| (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate) | (a) |
| | (a) |
| | (a) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
| (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%. |
| |
| (b) | Not applicableapplicable. |
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | Service Cost and Interest Cost | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Postretirement Benefit Obligation | Service Cost and Interest Cost | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Postretirement Benefit Obligation |
| 0.25% decrease in discount rate | $ | (1 | ) | | $ | 142 |
| | $ | — |
| | $ | 38 |
| $ | (1 | ) | | $ | 157 |
| | $ | — |
| | $ | 44 |
|
| 0.25% increase in salary scale | 2 |
| | 16 |
| | — |
| | — |
| 2 |
| | 15 |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | 3 |
| | 54 |
| — |
| | — |
| | 4 |
| | 71 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | (3 | ) | | (54 | ) | — |
| | — |
| | (4 | ) | | (71 | ) |
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees at December 31, 20162017. 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, 20162017, 20152016, and 20142015:
| | | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 16 |
| | $ | 16 |
| | $ | 16 |
| $ | 16 |
| | $ | 16 |
| | $ | 16 |
|
| Ameren Illinois | 12 |
| | 12 |
| | 11 |
| 13 |
| | 12 |
| | 12 |
|
| Other | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
| Ameren | 29 |
| | 29 |
| | 28 |
| 30 |
| | 29 |
| | 29 |
|
NOTE 1211 – STOCK-BASED COMPENSATION
The 2014 Incentive Plan is Ameren’s long-term stock compensation plan for eligible employees and directors. The 2006 Incentive Plan was replaced prospectively for new grants beginning in April 2014. The 2014 Incentive Plan provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors. At December 31, 2016,2017, there were 5.84.9 million common shares remaining for grant under the 2014 Incentive Plan. The 2014 Incentive Plan 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.
A 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 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 in 2015 and 2016 extendedextends beyond the three-year performance period to the payout date, while the vesting period for share units awarded in 2014 matched the three-year performance period and vested on December 31, 2016.date.
A summary ofThe following table summarizes the nonvested performance share units at December 31, 2016, and changes duringunit activity for the year ended December 31, 20162017, under the 2006 Incentive Plan and the 2014 Incentive Plan are presented below::
|
| | | | | | |
| | Performance Share Units |
| | Share Units | | Weighted-average Fair Value per Share Unit |
| Nonvested at January 1, 2016 | 1,024,870 |
| | $ | 46.08 |
|
Granted(a) | 588,615 |
| | 44.13 |
|
| Forfeitures | (15,949 | ) | | 45.07 |
|
Earned and vested(b) | (537,897 | ) | | 40.12 |
|
| Nonvested at December 31, 2016 | 1,059,639 |
| | $ | 48.04 |
|
|
| | | | | | |
| | 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 (share units) granted to certain executive and nonexecutive officers and other eligible employees in 20162017 under the 2014 Incentive Plan. |
| |
(b)(c) | Includes share units granted in 2014 that vested as of December 31, 2016 and were earned pursuant to the terms of the award grants. Also includesperformance 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, 2015 and 2014:2015:
| | | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 4 |
| | $ | 5 |
| | $ | 5 |
| $ | 4 |
| | $ | 4 |
| | $ | 5 |
|
| Ameren Illinois | 2 |
| | 3 |
| | 2 |
| 2 |
| | 2 |
| | 3 |
|
Other(a) | 11 |
| | 11 |
| | 12 |
| 12 |
| | 11 |
| | 11 |
|
| Ameren | 17 |
| | 19 |
| | 19 |
| 18 |
| | 17 |
| | 19 |
|
| Less income tax benefit | 6 |
| | 7 |
| | 7 |
| 7 |
| | 6 |
| | 7 |
|
| Stock-based compensation expense, net | $ | 11 |
| | $ | 12 |
| | $ | 12 |
| $ | 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 $83$39 million,, $27 $83 million,, and $33$27 million for the years ended December 31, 2017, 2016,, and 2015, and 2014. There were no significant compensation costs capitalized related to the performance share units during the years ended December 31, 20162017, 20152016, and 20142015. As of December 31, 20162017, total compensation cost of $2529 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 in 2016 under the 2014 Incentive Plan was determined to be $44.13, which wasis based on Ameren'sAmeren’s closing common share price at December 31st of $43.23 at December 31, 2015,the year prior to the award year and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren'sAmeren’s total shareholder return for a three-year3-year performance period relative to the designated peer group beginning January 1, 2016.1st of the award year. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because
they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also includedinclude a three-year risk-free rate, of 1.31%, volatility of 15% to 20% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.
The fair value of each share unit awarded in 2015 under the 2014 Incentive Plan was determined to be $52.88, which was based on Ameren’s closing common share price of $46.13 at December 31, 2014, and lattice simulations. The lattice simulations reflected the three-year performance period relative to the designated peer group beginning January 1, 2015. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.10%, volatility of 12% to 18% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.
The following table presents the fair value of each share unit awarded in 2014, excluding the grants issued in April 2014 for certain executive officers, under the 2006 Incentive Plan and the 2014 Incentive Plan was determined to be $38.90, which was based on Ameren’s closing common share price of $36.16 at December 31, 2013, and lattice simulations. The lattice simulations reflectedalong with the three-year performance period relative to the designated peer group beginning January 1, 2014. The significant assumptions used to calculate the fair value also included a three-year risk-free rate of 0.78%, volatility of 12% to 18%each share unit for the peer group,years ended December 31, 2017, 2016, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.2015:
|
| | | |
| | 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% |
NOTE 1312 – 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 taxes. Ameren (parent) will be subject to provisions of the TCJA that limit the deductibility of interest expense.
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 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 of December 31, 2017, the Ameren Companies have made reasonable estimates for the measurement and accounting of certain effects of the TCJA, which have been reflected in their financial statements. We have recorded provisional estimates 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 for 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 taxes are to be reflected in customer rates. This time period for the Ameren Companies is approximately 35 to 60 years. Other components of the excess deferred 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 – Rate and Regulatory Matters for information regarding the various proceedings for the TCJA impacts with our regulators.
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 does not expect this tax increase to have a material impact on its consolidated net income prospectively. The tax increase is not expected to materially impact 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 federalcorporate income tax rate for the years ended December 31, 20162017, 20152016, and 20142015:
| | | | Ameren Missouri | | Ameren Illinois | | Ameren | 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 | | | | | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | |
| 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 | 3 |
| | 5 |
| | 4 |
| 3 |
| | 5 |
| | 4 |
|
Stock-based compensation(a) | — |
| | — |
| | (2 | ) | — |
| | — |
| | (2 | ) |
| Valuation allowance | — |
| | — |
| | 1 |
| — |
| | — |
| | 1 |
|
| Other permanent items | — |
| | (2 | ) | | (1 | ) | — |
| | (2 | ) | | (1 | ) |
| Effective income tax rate | 38 | % | | 38 | % | | 37 | % | 38 | % | | 38 | % | | 37 | % |
| 2015 | | | | | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | |
| Federal statutory corporate income tax rate: | | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | | | | | |
| Depreciation differences | — |
| | (2 | ) | | (1 | ) | — |
| | (2 | ) | | (1 | ) |
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) | (1 | ) | | — |
| | (1 | ) |
| State tax | 3 |
| | 5 |
| | 5 |
| 3 |
| | 5 |
| | 5 |
|
| Other permanent items | — |
| | (1 | ) | | — |
| — |
| | (1 | ) | | — |
|
| Effective income tax rate | 37 | % | | 37 | % | | 38 | % | 37 | % | | 37 | % | | 38 | % |
| 2014 | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | |
| Increases (decreases) from: | | | | | | |
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) | |
| State tax | 3 |
| | 6 |
| | 4 |
| |
| Other permanent items | — |
| | — |
| | 1 |
| |
| Effective income tax rate | 37 | % | | 41 | % | | 39 | % | |
| |
| (a) | Reflects the adoption of new authoritative accounting guidance related to share-based compensation. See Note 1 – Summarycompensation, which resulted in the recognition of Significant Accounting Policies for more information.a $21 million income tax benefit in 2016. |
The following table presents the components of income tax expense (benefit) for the years ended December 31, 20162017, 20152016, and 20142015:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 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 |
|
| 2014 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | (13 | ) | | $ | (51 | ) | | $ | 27 |
| | $ | (37 | ) |
| State | (3 | ) | | (2 | ) | | (32 | ) | | (37 | ) |
| Deferred taxes: | | | | | | | |
| Federal | 222 |
| | 159 |
| | (12 | ) | | 369 |
|
| State | 28 |
| | 38 |
| | 22 |
| | 88 |
|
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense (benefit) | $ | 229 |
| | $ | 143 |
| | $ | 5 |
| | $ | 377 |
|
The Illinois corporate income tax rate was 9.5% in 2014. The tax rate decreased to 7.75% on January 1, 2015, and is scheduled to decrease to 7.3% on January 1, 2025. |
| | | | | | | | | | | | | | | |
| | 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 deferred tax liabilities recorded as a result of temporary differences at December 31, 20162017 and 20152016:
| | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2016 | | | | | | | | |
| 2017 | | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | | | | | | | | |
| Plant related | $ | 3,103 |
| | $ | 1,769 |
| | $ | 147 |
| | $ | 5,019 |
| $ | 2,064 |
| | $ | 1,264 |
| | $ | 146 |
| | $ | 3,474 |
|
| Regulatory assets, net | 75 |
| | (1 | ) | | — |
| | 74 |
| |
| Regulatory assets and liabilities, net | | (317 | ) | | (206 | ) | | (24 | ) | | (547 | ) |
| Deferred employee benefit costs | (76 | ) | | (38 | ) | | (97 | ) | | (211 | ) | (53 | ) | | (17 | ) | | (61 | ) | | (131 | ) |
| Revenue requirement reconciliation adjustments | — |
| | 34 |
| | — |
| | 34 |
| — |
| | 20 |
| | — |
| | 20 |
|
| Tax carryforwards | (66 | ) | | (138 | ) | | (472 | ) | | (676 | ) | (31 | ) | | (43 | ) | | (287 | ) | | (361 | ) |
| Other | (23 | ) | | 5 |
| | 42 |
| | 24 |
| (13 | ) | | 3 |
| | 61 |
| | 51 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 3,013 |
| | $ | 1,631 |
| | $ | (380 | ) | | $ | 4,264 |
| $ | 1,650 |
| | $ | 1,021 |
| | $ | (165 | ) | | $ | 2,506 |
|
| 2015 | | | | | | | | |
| 2016 | | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | | | | | | | | |
| Plant related | $ | 2,931 |
| | $ | 1,587 |
| | $ | 37 |
| | $ | 4,555 |
| $ | 3,103 |
| | $ | 1,769 |
| | $ | 147 |
| | $ | 5,019 |
|
| Regulatory assets, net | 81 |
| | (1 | ) | | — |
| | 80 |
| |
| Regulatory assets and liabilities, net | | 75 |
| | (1 | ) | | — |
| | 74 |
|
| Deferred employee benefit costs | (76 | ) | | (40 | ) | | (91 | ) | | (207 | ) | (76 | ) | | (38 | ) | | (97 | ) | | (211 | ) |
| Revenue requirement reconciliation adjustments | — |
| | 66 |
| | — |
| | 66 |
| — |
| | 34 |
| | — |
| | 34 |
|
| Tax carryforwards | (65 | ) | | (133 | ) | | (405 | ) | | (603 | ) | (66 | ) | | (138 | ) | | (472 | ) | | (676 | ) |
| Other | (27 | ) | | 1 |
| | 20 |
| | (6 | ) | (23 | ) | | 5 |
| | 42 |
| | 24 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 2,844 |
| | $ | 1,480 |
| | $ | (439 | ) | | $ | 3,885 |
| $ | 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, 20162017 and 2015:2016:
| | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2016 | | | | | | | | |
| 2017 | | | | | | | | |
| Net operating loss carryforwards: | | | | | | | | | | | | | | |
Federal(a) | $ | 33 |
| | $ | 137 |
| | $ | 324 |
| | $ | 494 |
| $ | — |
| | $ | 41 |
| | $ | 162 |
| | $ | 203 |
|
State(a) | 4 |
| | — |
| | 41 |
| | 45 |
| — |
| | — |
| | 32 |
| | 32 |
|
| Total net operating loss carryforwards | $ | 37 |
| | $ | 137 |
| | $ | 365 |
| | $ | 539 |
| $ | — |
| | $ | 41 |
| | $ | 194 |
| | $ | 235 |
|
| Tax credit carryforwards: | | | | | | | | | | | | | | |
Federal(a) | $ | 29 |
| | $ | 1 |
| | $ | 79 |
| | $ | 109 |
| |
Federal(b) | | $ | 31 |
| | $ | 2 |
| | $ | 80 |
| | $ | 113 |
|
State(b)(c) | — |
| | — |
| | 21 |
| | 21 |
| — |
| | — |
| | 7 |
| | 7 |
|
| Total tax credit carryforwards | $ | 29 |
| | $ | 1 |
| | $ | 100 |
| | $ | 130 |
| $ | 31 |
| | $ | 2 |
| | $ | 87 |
| | $ | 120 |
|
Charitable contribution carryforwards(b)(d) | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | 18 |
| $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 11 |
|
Valuation allowance(c)(e) | — |
| | — |
| | (11 | ) | | (11 | ) | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 7 |
| $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
|
| 2015 | | | | | | | | |
| 2016 | | | | | | | | |
| Net operating loss carryforwards: | | | | | | | | | | | | | | |
| Federal | $ | 35 |
| | $ | 127 |
| | $ | 245 |
| | $ | 407 |
| $ | 33 |
| | $ | 137 |
| | $ | 324 |
| | $ | 494 |
|
| State | 4 |
| | 4 |
| | 38 |
| | 46 |
| 4 |
| | — |
| | 41 |
| | 45 |
|
| Total net operating loss carryforwards | $ | 39 |
| | $ | 131 |
| | $ | 283 |
| | $ | 453 |
| $ | 37 |
| | $ | 137 |
| | $ | 365 |
| | $ | 539 |
|
| Tax credit carryforwards: | | | | | | | | | | | | | | |
| Federal | $ | 26 |
| | $ | 1 |
| | $ | 78 |
| | $ | 105 |
| $ | 29 |
| | $ | 1 |
| | $ | 79 |
| | $ | 109 |
|
| State | — |
| | 1 |
| | 40 |
| | 41 |
| — |
| | — |
| | 21 |
| | 21 |
|
| State valuation allowance | — |
| | — |
| | (2 | ) | | (2 | ) | |
| Total tax credit carryforwards | $ | 26 |
| | $ | 2 |
| | $ | 116 |
| | $ | 144 |
| $ | 29 |
| | $ | 1 |
| | $ | 100 |
| | $ | 130 |
|
| Charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 10 |
| | $ | 10 |
| $ | — |
| | $ | — |
| | $ | 18 |
| | $ | 18 |
|
| Valuation allowance | — |
| | — |
| | (4 | ) | | (4 | ) | — |
| | — |
| | (11 | ) | | (11 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
| $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 7 |
|
| |
| (a) | Will expire between 20292033 and 2036. Any net operating loss carryforward generated after January 1, 2018, will not have an expiration date as a result of the TCJA. |
| |
| (b) | Will expire between 20172029 and 2037. |
| |
| (c) | Will expire between2019 and 2022. |
| |
| (d) | Will expire between 2018 and 2021. |
| |
(c)(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, 20162017 and 2015,2016, the Ameren Companies did not record any uncertain tax positions. The settlements discussed below resolved previously recorded uncertain tax positions.
In 2015, final settlements for tax years 2012 and 2013 were reached with the IRS. The 2015 settlement of the 2013 tax year impactedaffected discontinued operations. See Note 1 – Summary of Significant Accounting Policies for additional information.
In 2014, final settlements for tax years 2007 through 2011 were reached with the IRS. These settlements, which resolved the uncertain tax positions associated with the timing of research tax deductions for these years, resulted in a decrease in Ameren’s and Ameren Missouri’s unrecognized tax benefits of $20 million, and $13 million, respectively. In addition, the settlement for tax years 2007 through 2011 provided certainty for the previously uncertain tax positions associated with the timing of research tax deductions for the remaining open tax years of 2012, 2013, and 2014. The certainty provided from the settlement resulted in an $18 million decrease in both Ameren’s and Ameren Missouri’s unrecognized tax benefits. The settlement also resulted in a $2 million increase to Ameren’s state unrecognized tax benefits. The net reduction in unrecognized tax benefits in 2014 did not materially affect income tax expense for the Ameren Companies.
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'sMissouri’s regulatory framework, uncertain tax positions do not reduce Ameren Missouri'sMissouri’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, using the weighted-average cost of capital 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 andcreated. It will then will be amortized over three years, beginning on the effective date of new rates established in the next electric regulatory rate case.review.
NOTE 1413 – RELATED PARTYRELATED-PARTY TRANSACTIONS
In the normal course of business, the Ameren CompaniesMissouri 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 affiliatesAmeren’s subsidiaries are reported as intercompanyaffiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. Below are the material related partyrelated-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'Illinois’ capacity requirements for $1 million and $3 million for the 12 months ended May 31, 2014, and 2015, respectively.2015. In a procurement event in 2015, Ameren Missouri contracted to supply a portion of Ameren Illinois'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 administeredIPA-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 timeperformance period, price, and amount of megawatthours included in each agreement:
| | IPA Procurement Event | Time Period | MWh | | Average Price per MWh | Performance Period | MWh |
| | Average Price per MWh |
| May 2014 | January 2015 – February 2017 | 168,400 |
| $ | 51 | January 2015 – February 2017 | 168,400 |
| $ | 51 |
| April 2015 | June 2015 – June 2017 | 667,000 |
| | 36 | June 2015 – June 2017 | 667,000 |
| | 36 |
| September 2015 | November 2015 – May 2018 | 339,000 |
| | 38 | November 2015 – May 2018 | 339,000 |
| | 38 |
| April 2016 | June 2017 – September 2018 | 375,200 |
| | 35 | June 2017 – September 2018 | 375,200 |
| | 35 |
| September 2016 | May 2017 – September 2018 | 82,800 |
| | 34 | 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, 20162017 and 2015,2016, 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'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. The costs of the rent and facility services are based on, or are an allocation of, actual costs incurred.
Separately, Ameren Missouri and Ameren Illinois 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 load in the AMIL pricing zone.
Money Pool
See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings for a discussion of affiliate borrowing arrangements.
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreementagreement. As of December 31, 2017 and the related2016, Ameren Missouri had income taxes payable to 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 and returnreceived related to the tax allocation agreement.
Capital Contributions
In 2017, Ameren Missouri received cash capital contributions of capital.
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 received cash capital contributions of $25 million from Ameren (parent).
The following table presents the impact on Ameren Missouri and Ameren Illinois of related partyrelated-party transactions for the years ended December 31, 20162017, 20152016, and 20142015. 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 | | 2016 | $ | 28 |
| $ | (a) |
| Operating Revenues | | 2017 | $ | 23 |
| $ | (a) |
|
| with Ameren Illinois | | 2015 | | 15 |
| | (a) |
| | 2016 | | 28 |
| | (a) |
|
| | | | 2014 | | 5 |
| | (a) |
| | | 2015 | | 15 |
| | (a) |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2016 | | 25 |
| | 5 |
| Operating Revenues | | 2017 | | 26 |
| | 4 |
|
| rent and facility services | | 2015 | | 25 |
| | 4 |
| | 2016 | | 25 |
| | 5 |
|
| | | | 2014 | | 21 |
| | 2 |
| | | 2015 | | 25 |
| | 4 |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2016 | | 1 |
| | (b) |
| Operating Revenues | | 2017 | | (b) |
| | 1 |
|
| miscellaneous support services | | 2015 | | 2 |
| | (b) |
| | 2016 | | 1 |
| | (b) |
|
| | | 2014 | | 1 |
| | (b) |
| | 2015 | | 2 |
| | (b) |
|
| Total Operating Revenues | | 2016 | $ | 54 |
| $ | 5 |
| | 2017 | $ | 49 |
| $ | 5 |
|
| | | 2015 | | 42 |
| | 4 |
| | 2016 | | 54 |
| | 5 |
|
| | | | 2014 | | 27 |
| | 2 |
| | | 2015 | | 42 |
| | 4 |
|
| Ameren Illinois power supply | Purchased Power | | 2016 | $ | (a) |
| $ | 28 |
| Purchased Power | | 2017 | $ | (a) |
| $ | 23 |
|
| agreements with Ameren Missouri | | 2015 | | (a) |
| | 15 |
| | 2016 | | (a) |
| | 28 |
|
| | | | 2014 | | (a) |
| | 5 |
| | | 2015 | | (a) |
| | 15 |
|
| Ameren Illinois transmission | Purchased Power | | 2016 | | (a) |
| | 2 |
| Purchased Power | | 2017 | | (a) |
| | 2 |
|
| services from ATXI | | 2015 | | (a) |
| | 2 |
| | 2016 | | (a) |
| | 2 |
|
| | | 2014 | | (a) |
| | 2 |
| | 2015 | | (a) |
| | 2 |
|
| Total Purchased Power | | 2016 | $ | (a) |
| $ | 30 |
| | 2017 | $ | (a) |
| $ | 25 |
|
| | | 2015 | | (a) |
| | 17 |
| | 2016 | | (a) |
| | 30 |
|
| | | 2014 | | (a) |
| | 7 |
| | 2015 | | (a) |
| | 17 |
|
| Ameren Services support services | Other Operations and | | 2016 | $ | 129 |
| $ | 123 |
| Other Operations and | | 2017 | $ | 149 |
| $ | 139 |
|
| agreement | Maintenance | | 2015 | | 131 |
| | 119 |
| Maintenance | | 2016 | | 129 |
| | 123 |
|
| | | | 2014 | | 124 |
| | 109 |
| | | 2015 | | 131 |
| | 119 |
|
| Money pool borrowings (advances) | Interest (Charges) | | 2016 | $ | (b) |
| $ | (b) |
| (Interest Charges) | | 2017 | $ | 1 |
| $ | (b) |
|
| | Income | | 2015 | | (b) |
| | (b) |
| Miscellaneous Income | | 2016 | | (b) |
| | (b) |
|
| | | | 2014 | | (b) |
| | (b) |
| | | 2015 | | (b) |
| | (b) |
|
| |
| (b) | Amount less than $1 million. |
NOTE 1514 – 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 these 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 109 – Callaway Energy Center, and Note 1413 – Related PartyRelated-party Transactions in this report.
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at December 31, 2016. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year.
|
| | | | | | | | |
| Type and Source of Coverage | Maximum Coverages | | Maximum Assessments | |
| Public liability and nuclear worker liability: | | | | |
| American Nuclear Insurers | $ | 375 |
| (a) | $ | — |
| |
| Pool participation | 12,986 |
| (b) | 127 |
| (c) |
| | $ | 13,361 |
| (d) | $ | 127 |
| |
| Property damage: | | | | |
| Nuclear Electric Insurance Limited | $ | 2,710 |
| (e) | $ | 30 |
| (f) |
| European Mutual Association for Nuclear Insurance | 450 |
| (g) | — |
| |
| | $ | 3,160 |
| | $ | 30 |
| |
| Replacement power: | | | | |
| Nuclear Electric Insurance Limited | $ | 490 |
| (h) | $ | 7 |
| (f) |
| |
(a) | Effective January 1, 2017, limit was increased to $450 million. |
| |
(b) | Provided through mandatory participation in an industrywide retrospective premium assessment program. |
| |
(c) | Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year.
|
| |
(d) | Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $127 million per incident for each licensed reactor it operates, with a maximum of $19 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
|
| |
(e) | NEIL provides $2.71 billion in property damage, decontamination, and premature decommissioning insurance for radiation events. NEIL provides $2.3 billion in property damage for nonradiation events. |
| |
(f) | All NEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL. |
| |
(g) | European Mutual Association for Nuclear Insurance provides $450 million in excess of the $2.71 billion and $2.3 billion property coverage for radiation and nonradiation events, respectively, provided by NEIL. |
| |
(h) | Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity is 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 sub-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. 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 are covered under NEIL’s insurance policies, subject to an industrywide aggregate policy coverage limit of $3.24 billion within a 12-month period, or $1.83 billion for events not involving radiation contamination.
If losses from a nuclear incident at the Callaway energy center exceed the limits of or are not covered by insurance, or if insurance 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, and liquidity.
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, 20162017:
| | | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | After 5 Years | | Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | After 5 Years | | Total |
Ameren:(a) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Minimum capital lease payments(b) | $ | 33 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 297 |
| | $ | 458 |
| |
Minimum capital lease payments(b)(c) | | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 27 |
| | 26 |
| | 25 |
| | 25 |
| | 25 |
| | 48 |
| | 176 |
| 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 7 |
| | $ | 249 |
| | $ | 282 |
| $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
Operating leases(c) | 13 |
| | 12 |
| | 12 |
| | 11 |
| | 10 |
| | 23 |
| | 81 |
| |
| Operating leases | | 10 |
| | 9 |
| | 8 |
| | 6 |
| | 6 |
| | 14 |
| | 53 |
|
| Total lease obligations | $ | 19 |
| | $ | 18 |
| | $ | 19 |
| | $ | 18 |
| | $ | 17 |
| | $ | 272 |
| | $ | 363 |
| $ | 16 |
| | $ | 16 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 329 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Minimum capital lease payments(b) | $ | 33 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 297 |
| | $ | 458 |
| |
Minimum capital lease payments(b)(c) | | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 27 |
| | 26 |
| | 25 |
| | 25 |
| | 25 |
| | 48 |
| | 176 |
| 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 7 |
| | $ | 249 |
| | $ | 282 |
| $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
Operating leases(c) | 11 |
| | 11 |
| | 11 |
| | 10 |
| | 9 |
| | 21 |
| | 73 |
| |
| Operating leases | | 8 |
| | 8 |
| | 7 |
| | 6 |
| | 6 |
| | 14 |
| | 49 |
|
| Total lease obligations | $ | 17 |
| | $ | 17 |
| | $ | 18 |
| | $ | 17 |
| | $ | 16 |
| | $ | 270 |
| | $ | 355 |
| $ | 14 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 325 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating leases(c) | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 6 |
| $ | 1 |
| | (d) |
| | (d) |
| | (d) |
| | (d) |
| | $ | 1 |
| | $ | 2 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | See Properties under Part I, Item 2, and Note 3 – Property, Plant, and Equipment, Net of this report for additional information. |
| |
| (c) | Amounts related to certain land-related leases have indefinite payment periods. The annual obligations of $3 million, $2 million,See Note 5 – Long-term Debt and $1 millionEquity Financings for Ameren, Ameren Missouri,additional information on Ameren’s and Ameren Illinois for these items are included in the 2017 through 2021 columns, respectively.Missouri’s capital lease agreements. |
The following table presents total rental expenseoperating lease expenses included in operating expenses“Operating Expenses” in the statement of income for the years ended December 31, 20162017, 20152016, and 20142015:
| | | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
Ameren(a) | $ | 38 |
| | $ | 36 |
| | $ | 37 |
| $ | 11 |
| | $ | 38 |
| | $ | 36 |
|
| Ameren Missouri | 34 |
| | 34 |
| | 32 |
| 10 |
| | 34 |
| | 34 |
|
| Ameren Illinois | 30 |
| | 28 |
| | 25 |
| 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 ourAmeren Missouri’s energy centers, we haveAmeren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. WeAmeren 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 for fuel at December 31, 20162017. Ameren’s and Ameren Missouri’s purchased power commitments include a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois power purchase 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, 20162017.
| | | | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b) | | Methane Gas | | Other | | Total | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b)(c) | | Methane Gas | | Other | | Total |
Ameren:(c)(d) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | $ | 599 |
| | $ | 238 |
| | $ | 45 |
| | $ | 255 |
| | $ | 3 |
| | $ | 118 |
| | $ | 1,258 |
| |
| 2018 | 371 |
| | 167 |
| | 70 |
| | 156 |
| | 4 |
| | 60 |
| | 828 |
| $ | 463 |
| | $ | 205 |
| | $ | 67 |
| | $ | 170 |
| | $ | 3 |
| | $ | 73 |
| | $ | 981 |
|
| 2019 | 311 |
| | 99 |
| | 27 |
| | 79 |
| | 4 |
| | 60 |
| | 580 |
| 383 |
| | 163 |
| | 26 |
| | 63 |
| | 4 |
| | 37 |
| | 676 |
|
| 2020 | 27 |
| | 45 |
| | 38 |
| | 58 |
| | 5 |
| | 56 |
| | 229 |
| 85 |
| | 110 |
| | 39 |
| | 14 |
| | 4 |
| | 36 |
| | 288 |
|
| 2021 | — |
| | 12 |
| | 44 |
| | 58 |
| | 5 |
| | 29 |
| | 148 |
| 27 |
| | 46 |
| | 45 |
| | 3 |
| | 5 |
| | 25 |
| | 151 |
|
| 2022 | | — |
| | 11 |
| | 12 |
| | 2 |
| | 5 |
| | 25 |
| | 55 |
|
| Thereafter | — |
| | 43 |
| | 45 |
| | 478 |
| | 65 |
| | 198 |
| | 829 |
| — |
| | 38 |
| | 45 |
| | 18 |
| | 58 |
| | 95 |
| | 254 |
|
| Total | $ | 1,308 |
| | $ | 604 |
| | $ | 269 |
| | $ | 1,084 |
| | $ | 86 |
| | $ | 521 |
| | $ | 3,872 |
| $ | 958 |
| | $ | 573 |
| | $ | 234 |
| | $ | 270 |
| | $ | 79 |
| | $ | 291 |
| | $ | 2,405 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | $ | 599 |
| | $ | 43 |
| | $ | 45 |
| | $ | 22 |
| | $ | 3 |
| | $ | 39 |
| | $ | 751 |
| |
| 2018 | 371 |
| | 29 |
| | 70 |
| | 22 |
| | 4 |
| | 29 |
| | 525 |
| $ | 463 |
| | $ | 42 |
| | $ | 67 |
| | $ | — |
| | $ | 3 |
| | $ | 53 |
| | $ | 628 |
|
| 2019 | 311 |
| | 15 |
| | 27 |
| | 22 |
| | 4 |
| | 29 |
| | 408 |
| 383 |
| | 36 |
| | 26 |
| | — |
| | 4 |
| | 24 |
| | 473 |
|
| 2020 | 27 |
| | 10 |
| | 38 |
| | 22 |
| | 5 |
| | 29 |
| | 131 |
| 85 |
| | 29 |
| | 39 |
| | — |
| | 4 |
| | 24 |
| | 181 |
|
| 2021 | — |
| | 5 |
| | 44 |
| | 22 |
| | 5 |
| | 28 |
| | 104 |
| 27 |
| | 13 |
| | 45 |
| | — |
| | 5 |
| | 25 |
| | 115 |
|
| 2022 | | — |
| | 6 |
| | 12 |
| | — |
| | 5 |
| | 25 |
| | 48 |
|
| Thereafter | — |
| | 18 |
| | 45 |
| | 59 |
| | 65 |
| | 183 |
| | 370 |
| — |
| | 16 |
| | 45 |
| | — |
| | 58 |
| | 75 |
| | 194 |
|
| Total | $ | 1,308 |
| | $ | 120 |
| | $ | 269 |
| | $ | 169 |
| | $ | 86 |
| | $ | 337 |
| | $ | 2,289 |
| $ | 958 |
| | $ | 142 |
| | $ | 234 |
| | $ | — |
| | $ | 79 |
| | $ | 226 |
| | $ | 1,639 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | $ | — |
| | $ | 195 |
| | $ | — |
| | $ | 233 |
| | $ | — |
| | $ | 36 |
| | $ | 464 |
| |
| 2018 | — |
| | 138 |
| | — |
| | 134 |
| | — |
| | 24 |
| | 296 |
| $ | — |
| | $ | 163 |
| | $ | — |
| | $ | 170 |
| | $ | — |
| | $ | 19 |
| | $ | 352 |
|
| 2019 | — |
| | 83 |
| | — |
| | 57 |
| | — |
| | 27 |
| | 167 |
| — |
| | 127 |
| | — |
| | 63 |
| | — |
| | 13 |
| | 203 |
|
| 2020 | — |
| | 35 |
| | — |
| | 36 |
| | — |
| | 27 |
| | 98 |
| — |
| | 81 |
| | — |
| | 14 |
| | — |
| | 12 |
| | 107 |
|
| 2021 | — |
| | 8 |
| | — |
| | 36 |
| | — |
| | — |
| | 44 |
| — |
| | 33 |
| | — |
| | 3 |
| | — |
| | — |
| | 36 |
|
| 2022 | | — |
| | 5 |
| | — |
| | 2 |
| | — |
| | — |
| | 7 |
|
| Thereafter | — |
| | 25 |
| | — |
| | 419 |
| | — |
| | — |
| | 444 |
| — |
| | 22 |
| | — |
| | 18 |
| | — |
| | — |
| | 40 |
|
| Total | $ | — |
| | $ | 484 |
| | $ | — |
| | $ | 915 |
| | $ | — |
| | $ | 114 |
| | $ | 1,513 |
| $ | — |
| | $ | 431 |
| | $ | — |
| | $ | 270 |
| | $ | — |
| | $ | 44 |
| | $ | 745 |
|
| |
| (a) | Includes amounts for generation and for distribution. |
| |
| (b) | The purchased power amounts for Ameren and Ameren Illinois includeexclude agreements through 2032 for renewable energy credits through 2032 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinoissuppliers due to reduce the quantity purchased incontingent nature of the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.payment amounts. |
| |
| (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) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
Environmental Matters
We are subject to various environmental laws 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 diverserespect to environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage, 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, 2016,2017, Ameren Missouri’s fossil-fueledfossil fuel-fired energy centers represented 18%17% and 34%33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations impactingthat apply to air emissions from the electric utility industry include the regulationNSPS, 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 existing power plants through the Clean Power Plan and from new power plants through the revised NSPS; the CSAPR, which requires further reductions of SO2 emissionsplants. Water intake and NOx emissions from power plants; a regulation governing management and storage of CCR; the MATS, which requires reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; effluent standards applicable to wastewater discharges from power plants; and regulationsplants are regulated under the Clean Water Act thatAct. Such regulation could require significant capital expenditures, such as 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 EPA also periodically reviews and revises national ambient air quality standards, including those standards associated with emissions from power plants, such as particulate matter, ozone, SO2 and NOx. Certain of these regulations are being or are likely to be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. Although many details of future regulations are unknown, the individual or combined effects of recentexisting environmental regulations could result in significant capital expenditures, and increased operating costs, for Ameren and Ameren Missouri. Compliance with these environmental laws and regulations could be prohibitively expensive, result inor the closure or alteration of the operation ofoperations at some of Ameren Missouri’s energy centers, or require further capital investment.centers. Ameren and Ameren Missouri expect that thesesuch compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the nature and timing of costs and their recovery could result inbe subject to regulatory lag.
Ameren Missouri'sMissouri’s current plan for compliance with existing environmentalair emission regulations for air emissions 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 million to $425 million to $525 million in the aggregate from 20172018 through 20212022 in order to comply with existing environmental regulations. Ameren Missouri may be required to install additional air emissionsAdditional environmental controls beyond 2021.2022 could be required. This estimate of capital expenditures includes expenditures required forby the CCR regulations, by the Clean Water Act rule applicable to cooling water intake structures at existing power plants, and the Clean Water Actby effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. This estimate does not include the potential impacts of the Clean Power Plan discussed below. 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 preciseEPA will substantially revise regulatory obligations, exactly which compliance strategies that will be used and their ultimate cost, among other things.
The following sections describe the more significant recent 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, including the effluent limitation guidelines and the CCR 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 in SO2 and NOx through either emission source reductions or 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, will becomebecame effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfur coal, operates two scrubbers at its Sioux energy center, and optimizes other existing pollution control equipment. Ameren Missouri doesdid not expect to 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, the EPA issued final regulations that setthe Clean Power Plan, which would have established CO2 emissions standards for new power plants. These new standards establish separate emissions limits for new natural-gas-fired combined cycle plants and new coal-fired plants.The Clean Power Plan sets forth CO2 emissions standards applicable to existing power plants. The rule was stayed by the United States Supreme Court stayed the rule in February 2016, pending the outcome of various legal challenges.
If upheld and implemented, In October 2017, the EPA announced a proposal to repeal the Clean Power Plan would require Missouri and IllinoisPlan. In December 2017, the EPA issued an advanced notice of proposed rulemaking to reducesolicit input from stakeholders as to how the EPA should regulate CO2 emissions from existing power plants within their states significantly below 2005 levels by 2030. The rule contains interim compliance periods commencing in 2022under the Clean Air Act. Accordingly, we no longer expect the Clean Power Plan to take effect. However, the EPA may issue new requirements that would require each state to demonstrate progress in achieving itsregulate CO2 emissions reduction target. Ameren continues to evaluate the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and to its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation. Significant uncertainty exists regarding the impact of the Clean Power Plan as its implementation will depend upon plans to be developed by the states. Numerous legal challenges are pending, which could result in the rule being declared invalid or the nature and timing of CO2 emissions reductions being revised. All implementation requirements are deferred until such time as these legal challenges are concluded. A decision by the District of Columbia Circuit Court of Appeals is expected to be issued in 2017, and subsequent appeals to the United States Supreme Court are likely.from existing power plants. We cannot predict the outcome of suchthe EPA’s future rulemaking or the outcome of any legal challenges or their impactrelating to such future rulemakings, any of which could have an adverse effect on our results of operations, financial position, orand liquidity. If the rule is ultimately upheld and not rescinded or altered significantly by the new federal administration, compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could in turn result in increased operating costs and require Ameren Missouri to make unplanned or accelerated capital expenditures. Ameren Missouri expects substantially all of these increased costs to be recoverable, subject to MoPSC prudence review, through higher rates to customers, which could be significant.
Federal and state legislation or regulations that mandate limits on the emission of CO2 may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. Mandatory limits on the emission of CO2 could increase costs for Ameren Missouri’s customers or have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity if regulators delay or deny recovery in rates of these compliance costs. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects 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 might benefit from increased investment to comply with CO2 emission limitations to the extent that the investments are reflected and recovered on a timely basis in rates charged to customers.
NSR and Clean Air 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, alleged that in performing projects at its Rush Island coal-fired energy 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 that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceedthen proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase of the litigation.phase. The EPA previously withdrew all claims for penalties and fines. No date has been set by 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 liability ruling to the United States Circuit Court of Appeals for the Eighth Circuit. A decision by the district court regarding the remedy phase of the litigation could occur in 2018.
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 pollution control equipment, as well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of this matter or the costs that might be incurred.
Clean Water Act
In 2014, the EPA issued its final rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing aquatic organisms impinged on the facility’s intake screens or entrained through the plant'splant’s cooling water system. Additionally, in 2015, the EPA issued its final rule to revise the effluent limitation guidelines applicable to steam electric generating units. Effluent limitation guidelines are 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 components in water discharges from power plants. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. All of Ameren Missouri’s coal-fired energy centers are subject toThe rule will be implemented during the effluent limitations rule. Implementation of both rules will occur during thepermit renewal process of each energy center’s water discharge permit, which will occur between 2018 and 2023.
Additionally, in 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 two specific waste streams so that it could potentially revise those standards.
Both the intake 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 if theirshould such implementation requiresrequire extensive modifications to the cooling water systems and water discharge systems at Ameren Missouri’s energy centers, and if thosesuch investments are not recovered on a timely basis in electric rates charged to Ameren Missouri’s customers.
AshCCR Management
In 2015, the EPA issued regulations regarding the management and disposal of CCR from coal firedcoal-fired energy centers. These regulations affect CCR disposal and handling costs at Ameren Missouri'sMissouri’s energy centers. They require closure of impoundments if performance criteria relating to groundwater impacts and location restrictions are not achieved. During 2015,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. Ameren and Ameren Missouri have AROs of $150 million recorded an increase toon their AROsrespective balance sheets as of December 31, 2017, associated with CCR storage facilities and acceleratedthat reflect the closure of certain CCR storage facilities at its energy centers as a result of the new regulations.regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2023. See Note 1 – Summary2024. Ameren Missouri also estimates it will need to make capital expenditures of Significant Accounting Policies in this report for additional information.
Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of$300 million to $350 million from 2018 through 2022 to implement its environmentalCCR management compliance plan.
Remediation
The Ameren Companies are involved in a number of remediation actions to clean up sites affected by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation actions 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, 2016,2017, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, which are in various stages of investigation, evaluation, remediation, and closure. Ameren Illinois estimates it could substantially conclude remediation efforts by 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs associated with its former MGP sites 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, 2016,2017, Ameren Illinois estimated the obligation related to these former MGP sites at $200$175 million to $268$249 million. Ameren and Ameren Illinois recorded a liability of $200$175 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. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property at Sauget Area 2 that was once used by others as a landfill.
In December 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, 2016,2017 and December 31, 2015,2016, 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.
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, filed a class action lawsuit in November 2011 against Ameren Missouri in the Circuit Court of St. Louis County, Missouri. The lawsuit alleges that Ameren Missouri failed to collect and pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. In December 2017, the court issued a final order approving a settlement agreement between Ameren Missouri and the municipalities. The settlement agreement requires Ameren Missouri to make payments representing certain tax receipts to the municipalities during the first quarter of 2018, in addition to payment of certain future gross receipts taxes. The future gross receipts taxes are recoverable from customers. Ameren and Ameren Missouri recorded immaterial current liabilities on their respective balance sheets as of December 31, 2016, and December 31, 2015, representing their estimate of2017, to represent the probable loss due as a result of this lawsuit. Ameren and Ameren Missouri believe there is a remote possibility that a liability relating to this lawsuit could be material to Ameren's and Ameren Missouri’s results of operations, financial position, and liquidity. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that Ameren Missouri will be successfulpayments made in its efforts.
NOTE 1615 – SEGMENT INFORMATION
During the fourth quarter of 2016, the Ameren Companies changed the manner in which performance is assessed and resources are allocated, driven by increasing investment in FERC-regulated electric transmission and Ameren Illinois electric distribution and natural gas distribution businesses, as well as the unique regulatory environment for each jurisdiction. Ameren now 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 composed of the aggregated electric transmission businesses of Ameren Illinois and ATXI and associated Ameren (parent) interest charges.ATXI. The category called Other primarily includes Ameren parent company activities and Ameren Services.
Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri, Ameren Illinois, and Ameren Illinois.ATXI.
Segment operating revenuerevenues and a majority of operating expenses are directly assignedrecognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expense,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.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 atin Ameren TransmissionTransmission’s and Ameren Illinois Transmission.Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.
Prior to the fourth quarter of 2016, Ameren had two segments: Ameren Missouri and Ameren Illinois, which comprised the operations of the respective subsidiaries. The category called Other primarily included Ameren parent company activities, Ameren Services, and ATXI. Prior-period presentation has been adjusted for comparative purposes to reflect the 2016 change in segments.
The following tables present information about the reported revenues, and specified items reflected in net income attributable to common shareholders, from continuing operations and capital expenditures by segment at Ameren and Ameren Illinois for the years ended December 31, 20162017, 20152016, and 20142015. 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 | | Consolidated | 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 |
| $ | 3,469 |
| | $ | 1,545 |
| | $ | 753 |
| | $ | 309 |
| | $ | — |
| | $ | — |
| | $ | 6,076 |
|
| Intersegment revenues | 54 |
| | 4 |
| | 1 |
| | 46 |
| (a) | — |
| | (105 | ) | | — |
| 54 |
| | 4 |
| | 1 |
| | 46 |
| (a) | — |
| | (105 | ) | | — |
|
| Depreciation and amortization | 514 |
| | 226 |
| | 55 |
| | 43 |
| | 7 |
| | — |
| | 845 |
| 514 |
| | 226 |
| | 55 |
| | 43 |
| | 7 |
| | — |
| | 845 |
|
| Interest income | 28 |
| | 11 |
| | — |
| | 1 |
| | 11 |
| | (11 | ) | | 40 |
| 28 |
| | 11 |
| | — |
| | 1 |
| | 11 |
| | (11 | ) | | 40 |
|
| Interest charges | 211 |
| | 72 |
| | 34 |
| | 58 |
| | 18 |
| | (11 | ) | | 382 |
| 211 |
| | 72 |
| | 34 |
| | 58 |
| (b) | 18 |
| | (11 | ) | | 382 |
|
| Income taxes | 216 |
| | 78 |
| | 39 |
| | 74 |
| | (25 | ) | | — |
| | 382 |
| 216 |
| | 78 |
| | 39 |
| | 74 |
| | (25 | ) | | — |
| | 382 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 357 |
| | 126 |
| | 59 |
| | 117 |
| | (6 | ) | | — |
| | 653 |
| 357 |
| | 126 |
| | 59 |
| | 117 |
| | (6 | ) | | — |
| | 653 |
|
| Capital expenditures | 738 |
| | 470 |
| | 181 |
| | 689 |
| | 4 |
| (b) | (6 | ) | | 2,076 |
| 738 |
| | 470 |
| | 181 |
| | 689 |
| | 4 |
| | (6 | ) | | 2,076 |
|
| 2015 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | $ | 3,566 |
| | $ | 1,529 |
| | $ | 782 |
| | $ | 219 |
| | $ | 2 |
| | $ | — |
| | $ | 6,098 |
| $ | 3,566 |
| | $ | 1,529 |
| | $ | 782 |
| | $ | 219 |
| | $ | 2 |
| | $ | — |
| | $ | 6,098 |
|
| Intersegment revenues | 43 |
| | 3 |
| | 1 |
| | 40 |
| (a) | — |
| | (87 | ) | | — |
| 43 |
| | 3 |
| | 1 |
| | 40 |
| (a) | — |
| | (87 | ) | | — |
|
| Depreciation and amortization | 492 |
| | 212 |
| | 52 |
| | 33 |
| | 7 |
| | — |
| | 796 |
| 492 |
| | 212 |
| | 52 |
| | 33 |
| | 7 |
| | — |
| | 796 |
|
| Interest income | 28 |
| | 12 |
| | — |
| | — |
| | 7 |
| | (6 | ) | | 41 |
| 28 |
| | 12 |
| | — |
| | — |
| | 7 |
| | (6 | ) | | 41 |
|
| Interest charges | 219 |
| | 71 |
| | 35 |
| | 35 |
| | 1 |
| | (6 | ) | | 355 |
| 219 |
| | 71 |
| | 35 |
| | 35 |
| (b) | 1 |
| | (6 | ) | | 355 |
|
| Income taxes | 209 |
| | 71 |
| | 24 |
| | 51 |
| | 8 |
| | — |
| | 363 |
| 209 |
| | 71 |
| | 24 |
| | 51 |
| | 8 |
| | — |
| | 363 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 352 |
| | 123 |
| | 37 |
| | 83 |
| | (16 | ) | | — |
| | 579 |
| 352 |
| | 123 |
| | 37 |
| | 83 |
| | (16 | ) | | — |
| | 579 |
|
| Capital expenditures | 622 |
| | 491 |
| | 133 |
| | 669 |
| | 2 |
| (b) | — |
| | 1,917 |
| 622 |
| | 491 |
| | 133 |
| | 669 |
| | 2 |
| | — |
| | 1,917 |
|
| 2014 | | | | | | | | | | | | | | |
| External revenues | $ | 3,526 |
| | $ | 1,401 |
| | $ | 976 |
| | $ | 150 |
| | $ | — |
| | $ | — |
| | $ | 6,053 |
| |
| Intersegment revenues | 27 |
| | 2 |
| | — |
| | 37 |
| (a) | — |
| | (66 | ) | | — |
| |
| Depreciation and amortization | 473 |
| | 197 |
| | 41 |
| | 26 |
| | 8 |
| | — |
| | 745 |
| |
| Interest income | 28 |
| | 7 |
| | — |
| | — |
| | 5 |
| | (3 | ) | | 37 |
| |
| Interest charges | 211 |
| | 63 |
| | 28 |
| | 26 |
| | 16 |
| | (3 | ) | | 341 |
| |
| Income taxes | 229 |
| | 75 |
| | 39 |
| | 38 |
| | (4 | ) | | — |
| | 377 |
| |
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 390 |
| | 113 |
| | 50 |
| | 51 |
| | (17 | ) | | — |
| | 587 |
| |
| Capital expenditures | 747 |
| | 403 |
| | 137 |
| | 491 |
| | 7 |
| (b) | — |
| | 1,785 |
| |
| |
| (a) | Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
| |
| (b) | Includes the eliminationAmeren Transmission interest charges include an allocation of intercompany transfers. financing costs from Ameren (parent). |
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 | | Consolidated | |
| 2017 | | | | | | | | | | | |
| External revenues | | $ | 1,569 |
| | $ | 743 |
| | $ | 216 |
| | $ | — |
| | $ | 2,528 |
| |
| Intersegment revenues | | — |
| | — |
| | 42 |
| (a) | (42 | ) | | — |
| |
| Depreciation and amortization | | 239 |
| | 59 |
| | 43 |
| | — |
| | 341 |
| |
| Interest income | | 7 |
| | — |
| | — |
| | — |
| | 7 |
| |
| Interest charges | | 73 |
| | 36 |
| | 35 |
| | — |
| | 144 |
| |
| Income taxes | | 83 |
| | 36 |
| | 47 |
| | — |
| | 166 |
| |
| Net income available to common shareholder | | 131 |
| | 60 |
| | 77 |
| | — |
| | 268 |
| |
| Capital expenditures | | 476 |
| | 245 |
| | 355 |
| | — |
| | 1,076 |
| |
| 2016 | | | | | | | | | | | | | | | | | | | | |
| External revenues | $ | 1,549 |
| | $ | 754 |
| | $ | 187 |
| | $ | — |
| | $ | 2,490 |
| | $ | 1,549 |
| | $ | 754 |
| | $ | 187 |
| | $ | — |
| | $ | 2,490 |
| |
| Intersegment revenues | — |
| | — |
| | 45 |
| (a) | (45 | ) | | — |
| | — |
| | — |
| | 45 |
| (a) | (45 | ) | | — |
| |
| Depreciation and amortization | 226 |
| | 55 |
| | 38 |
| | — |
| | 319 |
| | 226 |
| | 55 |
| | 38 |
| | — |
| | 319 |
| |
| Interest income | 11 |
| | — |
| | 1 |
| | — |
| | 12 |
| | 11 |
| | — |
| | 1 |
| | — |
| | 12 |
| |
| Interest charges | 72 |
| | 34 |
| | 34 |
| | — |
| | 140 |
| | 72 |
| | 34 |
| | 34 |
| | — |
| | 140 |
| |
| Income taxes | 78 |
| | 39 |
| | 41 |
| | — |
| | 158 |
| | 78 |
| | 39 |
| | 41 |
| | — |
| | 158 |
| |
| Net income available to common shareholder | 126 |
| | 59 |
| | 67 |
| | — |
| | 252 |
| | 126 |
| | 59 |
| | 67 |
| | — |
| | 252 |
| |
| Capital expenditures | 470 |
| | 181 |
| | 273 |
| | — |
| | 924 |
| | 470 |
| | 181 |
| | 273 |
| | — |
| | 924 |
| |
| 2015 | | | | | | | | | | | | | | | | | | | | |
| External revenues | $ | 1,532 |
| | $ | 783 |
| | $ | 151 |
| | $ | — |
| | $ | 2,466 |
| | $ | 1,532 |
| | $ | 783 |
| | $ | 151 |
| | $ | — |
| | $ | 2,466 |
| |
| Intersegment revenues | — |
| | — |
| | 38 |
| (a) | (38 | ) | | — |
| | — |
| | — |
| | 38 |
| (a) | (38 | ) | | — |
| |
| Depreciation and amortization | 212 |
| | 52 |
| | 31 |
| | — |
| | 295 |
| | 212 |
| | 52 |
| | 31 |
| | — |
| | 295 |
| |
| Interest income | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
| |
| Interest charges | 71 |
| | 35 |
| | 25 |
| | — |
| | 131 |
| | 71 |
| | 35 |
| | 25 |
| | — |
| | 131 |
| |
| Income taxes | 71 |
| | 24 |
| | 32 |
| | — |
| | 127 |
| | 71 |
| | 24 |
| | 32 |
| | — |
| | 127 |
| |
| Net income available to common shareholder | 123 |
| | 37 |
| | 54 |
| | — |
| | 214 |
| | 123 |
| | 37 |
| | 54 |
| | — |
| | 214 |
| |
| Capital expenditures | 491 |
| | 133 |
| | 294 |
| | — |
| | 918 |
| | 491 |
| | 133 |
| | 294 |
| | — |
| | 918 |
| |
| 2014 | | | | | | | | | | | |
| External revenues | $ | 1,403 |
| | $ | 976 |
| | $ | 119 |
| | $ | — |
| | $ | 2,498 |
| | |
| Intersegment revenues | — |
| | — |
| | 35 |
| (a) | (35 | ) | | — |
| | |
| Depreciation and amortization | 197 |
| | 41 |
| | 25 |
| | — |
| | 263 |
| | |
| Interest income | 7 |
| | — |
| | — |
| | — |
| | 7 |
| | |
| Interest charges | 63 |
| | 28 |
| | 21 |
| | — |
| | 112 |
| | |
| Income taxes | 75 |
| | 39 |
| | 29 |
| | — |
| | 143 |
| | |
| Net income available to common shareholder | 113 |
| | 50 |
| | 38 |
| | — |
| | 201 |
| | |
| Capital expenditures | 403 |
| | 137 |
| | 295 |
| | — |
| | 835 |
| | |
| |
| (a) | Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2016 | | | 2015 |
| Quarter ended | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 |
| Operating revenues | $ | 1,434 |
| | $ | 1,427 |
| | $ | 1,859 |
| | $ | 1,356 |
| | | $ | 1,556 |
| | $ | 1,401 |
| | $ | 1,833 |
| | $ | 1,308 |
|
| Operating income | 220 |
| | 325 |
| | 691 |
| | 145 |
| | | 256 |
| | 237 |
| | 626 |
| | 140 |
|
| Net income | 107 |
| | 148 |
| | 371 |
| | 33 |
| | | 110 |
| | 151 |
| | 345 |
| | 30 |
|
| Net income attributable to Ameren common shareholders – continuing operations | $ | 105 |
| | $ | 147 |
| | $ | 369 |
| | $ | 32 |
| | | $ | 108 |
| | $ | 98 |
| | $ | 343 |
| | $ | 30 |
|
| Net income (loss) attributable to Ameren common shareholders – discontinued operations | — |
| | — |
| | — |
| | — |
| | | — |
| | 52 |
| | — |
| | (1 | ) |
| Net income attributable to Ameren common shareholders | $ | 105 |
| | $ | 147 |
| | $ | 369 |
| | $ | 32 |
| | | $ | 108 |
| | $ | 150 |
| | $ | 343 |
| | $ | 29 |
|
| Earnings per common share – basic – continuing operations | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
| | | $ | 0.45 |
| | $ | 0.40 |
| | $ | 1.42 |
| | $ | 0.12 |
|
| Earnings per common share – basic – discontinued operations | — |
| | — |
| | — |
| | — |
| | | — |
| | 0.21 |
| | — |
| | — |
|
| Earnings per common share – basic | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
| | | $ | 0.45 |
| | $ | 0.61 |
| | $ | 1.42 |
| | $ | 0.12 |
|
Earnings per common share – diluted – continuing operations(a) | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
| | | $ | 0.45 |
| | $ | 0.40 |
| | $ | 1.41 |
| | $ | 0.12 |
|
| Earnings per common share – diluted – discontinued operations | — |
| | — |
| | — |
| | — |
| | | — |
| | 0.21 |
| | — |
| | — |
|
Earnings per common share – diluted(a) | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
| | | $ | 0.45 |
| | $ | 0.61 |
| | $ | 1.41 |
| | $ | 0.12 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | Net Income Available to Common Shareholder |
| March 31, 2016 | | $ | 741 |
| | $ | 63 |
| | $ | 15 |
| | $ | 14 |
|
| March 31, 2015 | | 800 |
| | 115 |
| | 42 |
| | 41 |
|
| June 30, 2016 | | 867 |
| | 197 |
| | 93 |
| | 92 |
|
| June 30, 2015 | | 884 |
| | 146 |
| | 62 |
| | 61 |
|
| September 30, 2016 | | 1,165 |
| | 431 |
| | 242 |
| | 241 |
|
| September 30, 2015 | | 1,171 |
| | 423 |
| | 240 |
| | 239 |
|
| December 31, 2016 | | 750 |
| | 54 |
| | 10 |
| | 10 |
|
| December 31, 2015 | | 754 |
| | 58 |
| | 11 |
| | 11 |
|
|
| | | | | | | | | | | | | | | | |
| Ameren Illinois Quarter ended | | Operating Revenues | | Operating Income | | Net Income | | Net Income Available to Common Shareholder |
| March 31, 2016 | | $ | 677 |
| | $ | 133 |
| | $ | 60 |
| | $ | 59 |
|
| March 31, 2015 | | 745 |
| | 120 |
| | 54 |
| | 53 |
|
| June 30, 2016 | | 542 |
| | 107 |
| | 46 |
| | 45 |
|
| June 30, 2015 | | 513 |
| | 83 |
| | 32 |
| | 31 |
|
| September 30, 2016 | | 676 |
| | 230 |
| | 119 |
| | 119 |
|
| September 30, 2015 | | 655 |
| | 189 |
| | 98 |
| | 98 |
|
| December 31, 2016 | | 595 |
| | 74 |
| | 30 |
| | 29 |
|
| December 31, 2015 | | 553 |
| | 74 |
| | 33 |
| | 32 |
|
|
| | | | | | | | | | | | | | | | |
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 |
|
| |
| (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, 2016,2017, 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, 2016,2017, 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, 2016.2017. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2016,2017, 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 20162017 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 20172018 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 20172018 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 16(a) Beneficial Ownership Reporting Compliance,” “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” 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. Galvin serves as chairman of Ameren’s audit and risk committee and Catherine S. Brune, J. Edward Coleman, and Ellen M. Fitzsimmons serve as members. The board of directors of Ameren has determined that Walter J. Galvin and J. Edward Coleman 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.ameren.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.ameren.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 20172018 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 20172018 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” 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, 2016,2017, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation 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 Equity Compensation Plans (excluding securities reflected in Column A) |
Equity compensation plans approved by security holders(b) | | 1,995,995 |
| | (c) |
| | 5,832,009 |
| | 1,834,043 |
| | (c) |
| | 4,893,953 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 1,995,995 |
| | (c) |
| | 5,832,009 |
| | 1,834,043 |
| | (c) |
| | 4,893,953 |
|
| |
| (a) | Pursuant to grants of performance share units (PSUs) under the 20062014 Incentive Plan, 721,360 of the securities represent the estimated number of PSUs that were vested as of December 31, 2016 (including accrued and reinvested dividends), and 1,213,0131,767,462 of the securities represent the target number of PSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 20162017 (including outstanding awards under the 2014 Incentive Plan as of December 31, 2016)2017). 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 return objectives established for such awards. For additional information about the PSUs, including payout calculations, see “Compensation Discussion and Analysis – Long-Term Incentives: Performance Share Unit Program ("PSUP"(“PSUP”)” in Ameren’s definitive proxy statement for its 20172018 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. Also, 61,62266,581 of the securities represent shares that may be issued as of December 31, 2016,2017, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for members of the board of directors. |
| |
| (b) | Consists of the 2006 Incentive Plan and the 2014 Incentive Plan. The 2014 Incentive Plan replaced the 2006 Incentive Plan for any new grants made after April 24, 2014. |
| |
| (c) | Earned PSUs and deferred compensation stock units are paid in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs and deferred compensation stock units do not have a 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 20172018 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 20172018 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 20172018 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 20172018 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 Person Transactions” 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 20172018 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 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, 2015, and 20142015 | |
Consolidated Statement of Comprehensive Income – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Consolidated Balance Sheet – December 31, 20162017 and 20152016 | |
Consolidated Statement of Cash Flows – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
| Ameren Missouri | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Balance Sheet – December 31, 20162017 and 20152016 | |
Statement of Cash Flows – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
| Ameren Illinois | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Balance Sheet – December 31, 20162017 and 20152016 | |
Statement of Cash Flows – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
| | |
| (a)(2) Financial Statement Schedules | |
Schedule I – | |
| Condensed Financial Information of Parent – Ameren: | |
Condensed Statement of Income (Loss) and Comprehensive Income (Loss) – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Condensed Balance Sheet – December 31, 20162017 and 20152016 | |
Condensed Statement of Cash Flows – Years Ended December 31, 2017, 2016, 2015, and 20142015 | |
Schedule II – | |
| Ameren | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016, 2015, and 20142015 | |
| Ameren Missouri | |
| Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016, and 2015 | |
| Ameren Illinois | |
| Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016, and 2015 | |
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, 2016, 2015, and 2014 | |
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 | | 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) | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
| Operating expenses | 14 |
| | 14 |
| | 11 |
| 13 |
| | 14 |
| | 14 |
|
| Operating loss | (14 | ) | | (14 | ) | | (11 | ) | (13 | ) | | (14 | ) | | (14 | ) |
| Equity in earnings of subsidiaries | 663 |
| | 600 |
| | 607 |
| 659 |
| | 663 |
| | 600 |
|
| Interest income from affiliates | 10 |
| | 6 |
| | 3 |
| 9 |
| | 10 |
| | 6 |
|
| Total other income (expense), net | (5 | ) | | (5 | ) | | 2 |
| |
| Total other expense, net | | — |
| | (5 | ) | | (5 | ) |
| Interest charges | 28 |
| | 3 |
| | 16 |
| 31 |
| | 28 |
| | 3 |
|
| Income tax (benefit) | (27 | ) | | 5 |
| | (2 | ) | 101 |
| | (27 | ) | | 5 |
|
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | 653 |
| | 579 |
| | 587 |
| 523 |
| | 653 |
| | 579 |
|
Net Income (Loss) Attributable to Ameren Common Shareholders – Discontinued Operations | — |
| | 51 |
| | (1 | ) | |
| Net Income Attributable to Ameren Common Shareholders – Discontinued Operations | | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 653 |
| | $ | 630 |
| | $ | 586 |
| $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | | | | | | |
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | $ | 653 |
| | $ | 579 |
| | $ | 587 |
| $ | 523 |
| | $ | 653 |
| | $ | 579 |
|
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(7), $3, and $(7), respectively | (20 | ) | | 6 |
| | (12 | ) | |
| 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 | 633 |
| | 585 |
| | 575 |
| 528 |
| | 633 |
| | 585 |
|
| Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | 51 |
| | (1 | ) | |
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 633 |
| | $ | 636 |
| | $ | 574 |
| $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
| | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET | | (In millions) | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 |
| Assets: | | | | | | |
| Cash and cash equivalents | $ | 1 |
| | $ | — |
| $ | — |
| | $ | 1 |
|
| Advances to money pool | 27 |
| | — |
| 13 |
| | 27 |
|
| Accounts receivable – affiliates | 31 |
| | 53 |
| 46 |
| | 31 |
|
| Miscellaneous accounts and notes receivable | 26 |
| | 3 |
| — |
| | 26 |
|
| Other current assets | 8 |
| | 9 |
| 8 |
| | 8 |
|
| Total current assets | 93 |
| | 65 |
| 67 |
| | 93 |
|
| Investments in subsidiaries | 7,498 |
| | 7,227 |
| 7,944 |
| | 7,498 |
|
| Note receivable – ATXI | 350 |
| | 290 |
| 75 |
| | 350 |
|
| Accumulated deferred income taxes, net | 419 |
| | 426 |
| 222 |
| | 419 |
|
| Other assets | 135 |
| | 158 |
| 140 |
| | 135 |
|
| Total assets | $ | 8,495 |
| | $ | 8,166 |
| $ | 8,448 |
| | $ | 8,495 |
|
| Liabilities and Shareholders’ Equity: | | | | | | |
| Short-term debt | 507 |
| | 301 |
| 383 |
| | 507 |
|
| Borrowings from money pool | 33 |
| | 14 |
| 28 |
| | 33 |
|
| Accounts payable – affiliates | 13 |
| | 75 |
| 6 |
| | 13 |
|
| Other current liabilities | 17 |
| | 22 |
| 27 |
| | 17 |
|
| Total current liabilities | 570 |
| | 412 |
| 444 |
| | 570 |
|
| Long-term debt | 694 |
| | 694 |
| 696 |
| | 694 |
|
| Pension and other postretirement benefits | 45 |
| | 33 |
| 37 |
| | 45 |
|
| Other deferred credits and liabilities | 83 |
| | 81 |
| 87 |
| | 83 |
|
| Total liabilities | 1,392 |
| | 1,220 |
| 1,264 |
| | 1,392 |
|
| Commitments and Contingencies (Notes 4 and 5) | | | | |
| Commitments and Contingencies (Note 4) | | | | |
| Shareholders’ Equity: | | | | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 | 2 |
| | 2 |
| |
| Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding | | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,556 |
| | 5,616 |
| 5,540 |
| | 5,556 |
|
| Retained earnings | 1,568 |
| | 1,331 |
| 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (23 | ) | | (3 | ) | (18 | ) | | (23 | ) |
| Total shareholders’ equity | 7,103 |
| | 6,946 |
| 7,184 |
| | 7,103 |
|
| Total liabilities and shareholders’ equity | $ | 8,495 |
| | $ | 8,166 |
| $ | 8,448 |
| | $ | 8,495 |
|
| | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2016, 2015, and 2014 | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015 | | 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) | | 2016 | | 2015 | | 2014 | | 2017 | | 2016 | | 2015 |
| Net cash flows provided by operating activities | | $ | 483 |
| | $ | 551 |
| | $ | 528 |
| | $ | 454 |
| | $ | 483 |
| | $ | 551 |
|
| Cash flows from investing activities: | | | | | | | | | | | | |
| Money pool advances, net | | (27 | ) | | 55 |
| | 279 |
| | 14 |
| | (27 | ) | | 55 |
|
| Notes receivable – affiliates, net | | (60 | ) | | (96 | ) | | (134 | ) | |
| Notes receivable – ATXI, net | | | 275 |
| | (60 | ) | | (96 | ) |
| Investments in subsidiaries | | (123 | ) | | (509 | ) | | (280 | ) | | (151 | ) | | (123 | ) | | (509 | ) |
| Distributions from subsidiaries | | — |
| | — |
| | 215 |
| |
| Proceeds from note receivable – Marketing Company | | — |
| | 20 |
| | 95 |
| |
| Contributions to note receivable – Marketing Company | | — |
| | (8 | ) | | (89 | ) | |
| Other | | 2 |
| | (24 | ) | | (12 | ) | | 6 |
| | 2 |
| | (12 | ) |
| Net cash flows provided by (used in) investing activities | | (208 | ) | | (562 | ) | | 74 |
| | 144 |
| | (208 | ) | | (562 | ) |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Dividends on common stock | | (416 | ) | | (402 | ) | | (390 | ) | | (431 | ) | | (416 | ) | | (402 | ) |
| Short-term debt, net | | 206 |
| | (284 | ) | | 217 |
| | (124 | ) | | 206 |
| | (284 | ) |
| Money pool borrowings, net | | 19 |
| | 14 |
| | — |
| | (5 | ) | | 19 |
| | 14 |
|
| Maturities of long-term debt | | — |
| | — |
| | (425 | ) | |
| Issuances of long-term debt | | — |
| | 700 |
| | — |
| | — |
| | — |
| | 700 |
|
| Capital issuance costs | | — |
| | (6 | ) | | — |
| |
| Debt issuance costs | | | — |
| | — |
| | (6 | ) |
| Share-based payments | | (83 | ) | | (12 | ) | | (14 | ) | | (39 | ) | | (83 | ) | | (12 | ) |
| Net cash flows provided by (used in) financing activities | | (274 | ) | | 10 |
| | (612 | ) | | (599 | ) | | (274 | ) | | 10 |
|
| Net change in cash and cash equivalents | | $ | 1 |
| | $ | (1 | ) | | $ | (10 | ) | | $ | (1 | ) | | $ | 1 |
| | $ | (1 | ) |
| Cash and cash equivalents at beginning of year | | — |
| | 1 |
| | 11 |
| | 1 |
| | — |
| | 1 |
|
| Cash and cash equivalents at end of year | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
|
| | | | | | | | | | | | | |
| Cash dividends received from consolidated subsidiaries | | $ | 465 |
| | $ | 575 |
| | $ | 340 |
| | $ | 362 |
| | $ | 465 |
| | $ | 575 |
|
| | | | | | | | | | | | | |
| Noncash investing activity – investments in subsidiaries | | — |
| | (38 | ) | | (19 | ) | | — |
| | — |
| | (38 | ) |
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 20162017
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 1413 – Related PartyRelated-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 – 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 2014, 2015, 2016, and 2016.2017.
Ameren Corporation (parent company only) had a total of $51$46 million in guarantees outstanding, primarily for ATXI, that were not recorded on its December 31, 20162017 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 – 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'sCorporation’s (parent company only) long-term debt, indenture provisions, and restricted cash balance.
NOTE 4 – COMMITMENTS AND CONTINGENCIES
See Note 1514 – 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 – INCOME TAXES
See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding the impacts of the TCJA on Ameren Corporation (parent company only).
| | SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014 | |
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, 2017, 2016, AND 2015 |
| (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: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 19 |
| | $ | 26 |
| | $ | 7 |
| | $ | 33 |
| | $ | 19 |
|
| 2016 | $ | 19 |
| | $ | 32 |
| | $ | 3 |
| | $ | 35 |
| | $ | 19 |
| 19 |
| | 32 |
| | 3 |
| | 35 |
| | 19 |
|
| 2015 | 21 |
| | 33 |
| | 5 |
| | 40 |
| | 19 |
| 21 |
| | 33 |
| | 5 |
| | 40 |
| | 19 |
|
| 2014 | 18 |
| | 36 |
| | 4 |
| | 37 |
| | 21 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 11 |
| | $ | (6 | ) | (c) | $ | — |
| | $ | — |
| | $ | 5 |
|
| 2016 | $ | 6 |
| | $ | 7 |
| | $ | (2 | ) | | $ | — |
| | $ | 11 |
| 6 |
| | 7 |
| | (2 | ) | | — |
| | 11 |
|
| 2015 | 10 |
| | 4 |
| | (8 | ) | | — |
| | 6 |
| 10 |
| | 4 |
| | (8 | ) | | — |
| | 6 |
|
| 2014 | 7 |
| | 3 |
| | — |
| | — |
| | 10 |
| |
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 7 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 7 |
|
| 2016 | $ | 7 |
| | $ | 10 |
| | $ | — |
| | $ | 10 |
| | $ | 7 |
| 7 |
| | 10 |
| | — |
| | 10 |
| | 7 |
|
| 2015 | 8 |
| | 13 |
| | — |
| | 14 |
| | 7 |
| 8 |
| | 13 |
| | — |
| | 14 |
| | 7 |
|
| 2014 | 5 |
| | 16 |
| | — |
| | 13 |
| | 8 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2016 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| — |
| | — |
| | — |
| | — |
| | — |
|
| 2015 | 1 |
| | — |
| | (1 | ) | | — |
| | — |
| 1 |
| | — |
| | (1 | ) | | — |
| | — |
|
| 2014 | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 12 |
| | $ | 17 |
| | $ | 7 |
| | $ | 24 |
| | $ | 12 |
|
| 2016 | $ | 12 |
| | $ | 22 |
| | $ | 3 |
| | $ | 25 |
| | $ | 12 |
| 12 |
| | 22 |
| | 3 |
| | 25 |
| | 12 |
|
| 2015 | 13 |
| | 20 |
| | 5 |
| | 26 |
| | 12 |
| 13 |
| | 20 |
| | 5 |
| | 26 |
| | 12 |
|
| 2014 | 13 |
| | 20 |
| | 4 |
| | 24 |
| | 13 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2016 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| — |
| | — |
| | — |
| | — |
| | — |
|
| 2015 | 1 |
| | — |
| | (1 | ) | | — |
| | — |
| 1 |
| | — |
| | (1 | ) | | — |
| | — |
|
| 2014 | 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.
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, 2017 | 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, 2017 |
Warner L. Baxter | | | | |
| | | |
/s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | February 28, 2017 |
Martin J. Lyons, Jr. | | | | |
| | | | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2017 |
Bruce A. Steinke | | | | |
| | | | | |
* | | Director | | February 28, 2017 |
Catherine S. Brune | | | | |
| | | | | |
* | | Director | | February 28, 2017 |
J. Edward Coleman | | | | |
| | | |
* | | Director | | February 28, 2017 |
Ellen M. Fitzsimmons | | | | |
| | | |
* | | Director | | February 28, 2017 |
Rafael Flores | | | | |
| | | | | |
* | | Director | | February 28, 2017 |
Walter J. Galvin | | | | |
| | | |
* | | Director | | February 28, 2017 |
Richard J. Harshman | | | | |
| | | |
* | | Director | | February 28, 2017 |
Gayle P. W. Jackson | | | | |
| | | |
* | | Director | | February 28, 2017 |
James C. Johnson | | | | |
| | | |
* | | Director | | February 28, 2017 |
Steven H. Lipstein | | | | |
| | | |
* | | Director | | February 28, 2017 |
Stephen R. Wilson | | | | |
| | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2017 |
|
| | | | | |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
|
| | | | |
| | UNION ELECTRIC COMPANY (registrant)
|
| | | |
Date: | February 28, 2017 | By | | /s/ Michael L. Moehn |
| | | | Michael L. Moehn
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. Moehn | | Chairman and President, and Director (Principal Executive Officer) | | February 28, 2017 |
Michael L. Moehn | | | | |
| | | |
/s/ Martin J. Lyons, Jr.
| | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 2017 |
Martin J. Lyons, Jr. | | | | |
| | | |
/s/ Bruce A. Steinke
| | Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2017 |
Bruce A. Steinke | | | | |
| | | | | |
* | | Director | | February 28, 2017 |
Mark C. Birk | | | | |
| | | |
* | | Director | | February 28, 2017 |
Fadi M. Diya | | | | |
| | | |
* | | Director | | February 28, 2017 |
Gregory L. Nelson | | | | |
| | | |
* | | Director | | February 28, 2017 |
David N. Wakeman | | | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2017 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
|
| | | | |
| | AMEREN ILLINOIS COMPANY (registrant)
|
| | | | |
Date: | February 28, 2017 | 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 Executive Officer) | | February 28, 2017 |
Richard J. Mark | | | | |
| | | |
/s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 2017 |
Martin J. Lyons, Jr. | | | | |
| | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2017 |
Bruce A. Steinke | | | | |
| | | | | |
* | | Director | | February 28, 2017 |
Craig D. Nelson | | | | |
| | | |
* | | Director | | February 28, 2017 |
Gregory L. Nelson | | | | |
| | | | | |
* | | Director | | February 28, 2017 |
David N. Wakeman | | | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2017 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
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: |
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession |
2.1 | Ameren | Transaction Agreement, dated as of March 14, 2013, between Ameren Corporation and Illinois Power Holdings, LLC | March 19, 2013 Form 8-K, Exhibit 2.1, File No. 1-14756 |
2.2 | Ameren | Letter Agreement, dated December 2, 2013, between Ameren Corporation and Illinois Power Holdings, LLC, amending the Transaction Agreement, dated as of March 14, 2013 | December 4, 2013 Form 8-K, Exhibit 2.2, File No. 1-14756 |
| 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 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 |
| 4.5 | Ameren Ameren Missouri | | August 2, 1956 Form 8-K, Exhibit 2,4.22, File No. 1-2967333-222108 |
| 4.6 | Ameren Ameren Missouri | | April 1971 Form 8-K, Exhibit 6,
4.23, File No. 1-2967 333-222108 |
| 4.7 | Ameren Ameren Missouri | | February 1974 Form 8-K, Exhibit 3,
4.24, File No. 1-2967 333-222108 |
| 4.8 | Ameren Ameren Missouri | | Exhibit 4.6,4.25, File No. 2-69821333-222108 |
| 4.9 | 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, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.13 | Ameren Ameren Missouri | | August 4, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.14 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated October 1, 2003, relative to Series EE | October 8, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.15 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004A (1998A) | March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967 |
4.16 |
| | | |
| 4.15 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967 |
4.174.16 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967 |
4.184.17 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967 |
4.194.18 | Ameren Ameren Missouri | | May 18,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 | | September 23, 2004July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967 |
| 4.21 | Ameren Ameren Missouri | | January 27, 2005April 8, 2008 Form 8-K, Exhibit 4.4,4.7,
File No. 1-2967 |
| 4.22 | Ameren Ameren Missouri | | July 21, 2005June 19, 2008 Form 8-K, Exhibit 4.4,4.5,
File No. 1-2967 |
| 4.23 | Ameren Ameren Missouri | | June 15, 2007March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967 |
| 4.24 | Ameren Ameren Missouri | | April 8, 2008 Form 8-K, Exhibit 4.7,
4.45, File No. 1-2967 333-182258 |
| 4.25 | Ameren Ameren Missouri | | June 19, 2008September 11, 2012 Form 8-K, Exhibit 4.5,4.4,
File No. 1-2967 |
| 4.26 | Ameren Ameren Missouri | | March 23, 2009April 4, 2014 Form 8-K, Exhibit 4.5,
File No. 1-2967 |
| 4.27 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated May 15, 2012 | Exhibit 4.45, File No. 333-182258 |
4.28 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2012 relative to Series OO | September 11, 2012 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.29 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2014 relative to Series PP | April 4, 2014 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.30 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated March 15, 2015 relative to Series QQ | April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967 |
4.314.28 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.29 | 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 |
4.324.30 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.10, File No. 1-2967 |
4.334.31 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967 |
4.344.32 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.11, File No. 1-2967 |
4.354.33 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967 |
4.364.34 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.12, File No. 1-2967 |
|
| | | |
4.374.35 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967 |
4.384.36 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.13, File No. 1-2967 |
4.394.37 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967 |
4.404.38 | Ameren Ameren Missouri | | Exhibit 4.48, File No. 333-182258 |
4.41 |
| | | |
| 4.39 | 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 | | August 4, 2003January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.43 | Ameren Ameren Missouri | | September 23, 2004July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.44 | Ameren Ameren Missouri | | January 27, 2005April 8, 2008 Form 8-K, Exhibits 4.24.3 and 4.3,4.5, File No. 1-2967 |
| 4.45 | Ameren Ameren Missouri | | July 21, 2005June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.46 | Ameren Ameren Missouri | | June 15, 2007March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.47 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order, dated April 8, 2008, establishing the 6.00% Senior Secured Notes due 2018 (including the global note) | April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967 |
4.48 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated June 19, 2008, establishing the 6.70% Senior Secured Notes due 2019 (including the global note) | June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.49 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated March 20, 2009, establishing the 8.45% Senior Secured Notes due 2039 (including the global note) | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.50 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated September 11, 2012, establishing the 3.90% Senior Secured Notes due 2042 (including(including the global note) | September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967 |
4.514.48 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.524.49 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.534.50 | Ameren Ameren Missouri | | June 30,23, 2016 Form 10-Q, Exhibit 4.1,8-K, Exhibits 4.3, and 4.4, File No. 1-2967 |
4.544.51 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.52 | Ameren Ameren Illinois | | Exhibit 4.4, File No. 333-59438 |
4.554.53 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.564.54 | Ameren Ameren Illinois | | Exhibit 4.17, File No. 333-166095 |
4.574.55 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
4.584.56 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
4.594.57 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
|
| | | |
4.604.58 | 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 |
4.614.59 | Ameren Ameren Illinois | | December 1949 Form 8-K, Exhibit A, File No. 1-2732 |
4.624.60 | Ameren Ameren Illinois | | July 1957 Form 8-K, Exhibit A, File No. 1-2732 |
|
4.63 | | | |
| 4.61 | Ameren Ameren Illinois | | February 1966 Form 8-K, Exhibit A, File No. 1-2732 |
4.644.62 | Ameren Ameren Illinois | | January 30, 1992 Form 8-K, Exhibit 4(b), File No. 1-2732 |
4.654.63 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
4.664.64 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
4.674.65 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732 |
4.684.66 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.1, File No. 1-3672 |
4.694.67 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
4.704.68 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732 |
4.714.69 | 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 |
4.724.70 | Ameren Ameren Illinois | Supplemental Indenture, dated as of March 1, 1998, to Ameren Illinois Mortgage for Series S | Exhibit 4.41, File No. 333-71061 |
4.73 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of March 1, 1998, to Ameren Illinois Mortgage for Series T | Exhibit 4.42, File No. 333-71061 |
4.74 | Ameren
Ameren Illinois
| Supplemental Indenture amending the Ameren Illinois Mortgage dated as of June 15, 1999 | June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004 |
4.754.71 | Ameren Ameren Illinois | Supplemental Indenture, dated as of July 15, 1999, to Ameren Illinois Mortgage for Series U | June 30, 1999 Form 10-Q, Exhibit 4.4, File No. 1-3004 |
4.76 | Ameren
Ameren Illinois
| Supplemental Indenture amending the Ameren Illinois Mortgage dated as of December 15, 2002 | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 |
4.774.72 | Ameren Ameren Illinois | Supplemental Indenture, dated as of November 15, 2007, to Ameren Illinois Mortgage for Series BB | November 20, 2007 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.78 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of April 1, 2008, to Ameren Illinois Mortgage for Series CC | April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004 |
4.794.73 | Ameren Ameren Illinois | | October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.804.74 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.9, File No. 1-3672 |
4.814.75 | Ameren Ameren Illinois | | Exhibit 4.78, File No. 333-182258 |
4.824.76 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibit 4.4,4.5, File No. 1-3672 |
4.834.77 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
|
| | | |
4.844.78 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.854.79 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.864.80 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.874.81 | Ameren Ameren Illinois | | September 30, 2017 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
| 4.82 | Ameren Ameren Illinois | | November 28, 2017 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.83 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.884.84 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.5, File No. 1-14756 |
4.894.85 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
4.904.86 | Ameren Ameren Illinois | | Exhibit 4.83, File No. 333-182258 |
4.91 |
| | | |
| 4.87 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order, dated November 15, 2007, establishing the 6.125% Senior Secured Notes due 2017 (including the global note) | November 20, 2007 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.92 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order, dated April 8, 2008, establishing the 6.25% Senior Secured Notes due 2018 (including the global note) | April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.934.88 | Ameren Ameren Illinois | | October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.944.89 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-30041-3672 |
4.954.90 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.964.91 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.974.92 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.984.93 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.994.94 | Ameren Ameren Illinois | | December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 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, 2016 Form 8-K, Exhibit 10.1, File No. 1-2967 |
| 10.3 | Ameren Ameren Illinois | | December 8, 2016 Form 8-K, Exhibit 10.2, File No. 1-3672 |
| 10.4 | Ameren | | 2015 Form 10-K, Exhibit 10.4, File No. 1-14756 |
| 10.5 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
| 10.6 | Ameren Companies | | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 |
| 10.7 | Ameren Companies | | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
|
| | | |
| 10.8 | Ameren Companies | | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756 |
| 10.9 | Ameren Companies | | 2010 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.10 | Ameren Companies | | March 31, 2014 Form 10-Q,10-K, Exhibit 10.1,10.13, File No. 1-14756 |
| 10.11 | Ameren Companies | | 20142015 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 | | |
| 10.14 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1310.15 | Ameren Companies | | |
10.14 | Ameren Companies | *20142016 Base Salary Table for Named Executive Officers | 2013 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.15 | Ameren Companies | *2015 Base Salary Table for Named Executive Officers | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.16 | Ameren Companies | | 20152016 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.17 | Ameren Companies | | |
| 10.18 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 |
| 10.19 | Ameren Companies | | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
| 10.20 | Ameren Companies | | |
|
| | | |
| 10.21 | Ameren Companies | *Formula for Determining 2014 Target Performance Share Unit Awards to be Issued to Named Executive Officers | March 31, 2014 Form 10-Q, Exhibit 10.2, File No. 1-14756 |
10.22 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.17,10.24, File No. 1-14756 |
10.2310.22 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2410.23 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.24, File No. 1-14756 |
| 10.24 | Ameren Companies | | |
| 10.25 | Ameren Companies | *Ameren Corporation 2006 Omnibus Incentive Compensation Plan | February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756 |
10.26 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Awards Issued in 2014 pursuant to 2006 Omnibus Incentive Compensation Plan | March 31, 2014 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
10.27 | Ameren Companies | | Exhibit 99, File No. 333-196515 |
10.2810.26 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Awards Issued in 2014 pursuant to 2014 Omnibus Incentive Compensation Plan | 2014 Form 10-K, Exhibit 10.30, File No. 1-14756 |
10.29 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.3010.27 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.3110.28 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.31, File No. 1-14756 |
| 10.29 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.1, File No. 1-14756 |
| 10.30 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.2, File No. 1-14756 |
| 10.31 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.3, File No. 1-14756 |
| 10.32 | Ameren Companies | | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
| 10.33 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 |
| Statement re: Computation of Ratios |
| 12.1 | Ameren | Ameren's | |
| 12.2 | Ameren Missouri | | |
| 12.3 | Ameren Illinois | | |
| 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 | Consent of Independent Registered Public Accounting Firm with respect to Ameren | |
23.2 | Ameren Missouri | Consent of Independent Registered Public Accounting Firm with respect to Ameren Missouri | |
23.3 | Ameren Illinois | Consent of Independent Registered Public Accounting Firm with respect to Ameren Illinois | |
Power of Attorney |
24.1 | Ameren | Powers of Attorney with respect to Ameren | |
24.2 | Ameren Missouri | Powers of Attorney with respect to Ameren Missouri | |
24.3 | Ameren Illinois | Powers of Attorney with respect to Ameren Illinois | |
Rule 13a-14(a)/15d-14(a) Certifications |
31.1 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren | |
31.2 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren | |
31.3 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri | |
31.4 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of 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 File |
| 101.INS | Ameren Companies | XBRL Instance 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 | |
The file number references for the Ameren Companies'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
155Pursuant 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.
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| | | | |
| | AMEREN CORPORATION (registrant) |
| | | |
| Date: | February 28, 2018 | 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, 2018 |
| Warner L. Baxter | | | | |
| | | |
| /s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| | | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2018 |
| Bruce A. Steinke | | | | |
| | | | | |
| * | | Director | | February 28, 2018 |
| Catherine S. Brune | | | | |
| | | | | |
| * | | Director | | February 28, 2018 |
| J. Edward Coleman | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Ellen M. Fitzsimmons | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Rafael Flores | | | | |
| | | | | |
| * | | Director | | February 28, 2018 |
| Walter J. Galvin | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Richard J. Harshman | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Gayle P. W. Jackson | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| James C. Johnson | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Steven H. Lipstein | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Stephen R. Wilson | | | | |
| | | |
| | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
|
| | | | |
| | UNION ELECTRIC COMPANY (registrant) |
| | | |
| Date: | February 28, 2018 | By | | /s/ Michael L. Moehn |
| | | | Michael L. Moehn 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. Moehn | | Chairman and President, and Director (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, 2018 |
| Martin J. Lyons, Jr. | | | | |
| | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2018 |
| Bruce A. Steinke | | | | |
| | | | | |
| * | | Director | | February 28, 2018 |
| Mark C. Birk | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Fadi M. Diya | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Gregory L. Nelson | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| David N. Wakeman | | | | |
| | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
|
| | | | |
| | AMEREN ILLINOIS COMPANY (registrant) |
| | | | |
| Date: | February 28, 2018 | 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 Executive Officer) | | February 28, 2018 |
| Richard J. Mark | | | | |
| | | |
| /s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2018 |
| Bruce A. Steinke | | | | |
| | | | | |
| * | | Director | | February 28, 2018 |
| Craig D. Nelson | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| Gregory L. Nelson | | | | |
| | | | | |
| * | | Director | | February 28, 2018 |
| David N. Wakeman | | | | |
| | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
