UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
|
| | |
| (X) | | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2015.2017. |
| | |
| | | OR |
| | |
| ( ) | | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to . |
|
| | | | |
Commission File Number | | Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | | IRS Employer Identification No. |
| | | |
| 1-14756 | | Ameren Corporation | | 43-1723446 |
| | | (Missouri Corporation) | | |
| | | 1901 Chouteau Avenue | | |
| | | St. Louis, Missouri 63103 | | |
| | | (314) 621-3222 | | |
| | | |
| 1-2967 | | Union Electric Company | | 43-0559760 |
| | | (Missouri Corporation) | | |
| | | 1901 Chouteau Avenue | | |
| | | St. Louis, Missouri 63103 | | |
| | | (314) 621-3222 | | |
| | | |
| 1-3672 | | 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:
|
| | | |
| 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:
|
| | | |
| 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.
|
| | | | |
| Ameren Corporation | Yes | (X)ý
| No | ( )¨
|
| Union Electric Company | Yes | ( )¨
| No | (X)ý
|
| Ameren Illinois Company | Yes | (X)¨
| No | ( )ý
|
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
|
| | | | |
| Ameren Corporation | Yes | ( )¨
| No | (X)ý
|
| Union Electric Company | Yes | ( )¨
| No | (X)ý
|
| Ameren Illinois Company | Yes | ( )¨
| No | (X)ý
|
Indicate by checkmark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
|
| | | | |
| Ameren Corporation | Yes | (X)ý
| No | ( )¨
|
| Union Electric Company | Yes | (X)ý
| No | ( )¨
|
| Ameren Illinois Company | Yes | (X)ý
| No | ( )¨
|
Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
|
| | | | |
| Ameren Corporation | Yes | (X)ý
| No | ( )¨
|
| Union Electric Company | Yes | (X)ý
| No | ( )¨
|
| Ameren Illinois Company | Yes | (X)ý
| No | ( )¨
|
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.
|
| | |
| Ameren Corporation | | (X)ý
|
| Union Electric Company | | (X)ý
|
| Ameren Illinois Company | | (X)ý
|
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.
|
| | | | | | | | | | |
| | | Large Accelerated Filer | | Accelerated Filer | | Non-accelerated Filer | | Smaller Reporting Company | | Emerging Growth Company |
| Ameren Corporation | | (X)ý | | ( )¨ | | ( )¨
| | ( )¨
| | ¨ |
| Union Electric Company | | ( )¨
| | ( )¨
| | (X)ý
| | ( )¨ | | ¨ |
| Ameren Illinois Company | | ( )¨
| | ( )¨
| | (X)ý
| | ( )¨ | | ¨ |
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. |
| |
| 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).
|
| | | | |
| Ameren Corporation | Yes | ( )¨
| No | (X)ý
|
| Union Electric Company | Yes | ( )¨
| No | (X)ý
|
| Ameren Illinois Company | Yes | ( )¨
| No | (X)ý
|
As of June 30, 20152017, 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, 20152017) held by nonaffiliates was $9,142,479,189. 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, 20152017.
The number of shares outstanding of each registrant’s classes of common stock as of January 29,31, 20162018, waswere as follows:
|
| |
| Ameren Corporation | Common stock, $0.01 par value per share: 242,634,798 |
| | |
| Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): 102,123,834 |
| | |
| 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 20162018 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
|
| | |
| | | Page |
| |
| |
| PART I | | |
| Item 1. | | |
| | | |
| | | |
| | | |
| | | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Item 1A. | | |
| Item 1B. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
| |
| | | |
| PART II | | |
| Item 5. | | |
| Item 6. | | |
| Item 7. | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Item 7A. | | |
| Item 8. | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | | |
| Item 9. | | |
| Item 9A. | | |
| Item 9B. | | |
| | | |
| PART III | | |
| Item 10. | | |
| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
| | | |
| PART IV | | |
| Item 15. | | |
| Item 16. | | |
| |
| |
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 provides for compensatory stock-based awards to eligible employees and directors. The 2006 Omnibus Incentive Compensation Plan was replaced prospectively for new grants by the 2014 Incentive Plan.
2014 Incentive Plan -– The 2014 Omnibus Incentive Compensation Plan, which became effective in April 2014 and provides for compensatory stock-based awards to eligible employees and 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. Medina Valley was distributed from AER to Ameren in March 2013.
AERG - Ameren Energy Resources Generating Company, a former AER subsidiary that operated a merchant electric generation business in Illinois. In December 2013, AERG was included in the divestiture of New AER to IPH. Following the New AER divestiture, AERG became Illinois Power Resources Generating, LLC.
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 or AICElectric 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 Illinois is also defined as a financial reporting segment.
Ameren Illinois Merger - In 2010, CILCO and IP merged with and into CIPS, with the surviving corporation renamed Ameren Illinois Company.
Ameren Missouri or AMO -– 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.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 operated rate-regulated electricwas merged with CIPS and natural gas transmission and distribution businesses in Illinois, before theIP to form Ameren Illinois Merger.Illinois.
CIPS -– Central Illinois Public Service Company, ana predecessor to Ameren Corporation subsidiary, renamed Ameren Illinois Company upon the effectiveness of the Ameren Illinois Merger, which operates rate-regulated electric and natural gas transmission and distribution businesses in 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-firedfossil-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 down-winddownwind states to limit air emissions from fossil fuel-firedfossil-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 - Dynegy Inc.– Electric revenues less fuel and purchased power costs.
EEIEMANI - Electric Energy, Inc., a former 80%-owned Genco subsidiary that operated merchant electric generation energy centers and FERC-regulated transmission facilities in Illinois. In December 2013, Genco's ownership interest in EEI was included in the divestiture of New AER to IPH.– 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.
amended.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-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.
Genco - Ameren Energy Generating Company, a former AER subsidiary that operated a merchant electric generation business in Illinois and held an 80% ownership interest in EEI. In December 2013, Genco was included in the divestiture of New AER to IPH. Following the New AER divestiture, Genco became Illinois Power Generating Company.
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 deliverydistribution 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 multiyear senior unsecured credit agreement. The agreement, was amended and restatedwhich expires in December 2014 and is currently scheduled to expire on December 11, 2019.2021, unless extended.
IP -– Illinois Power Company, a former Ameren Corporation subsidiary that operated rate-regulated electricmerged with CIPS and natural gas transmission and distribution businesses in Illinois, before theCILCO to form Ameren Illinois Merger.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, which is a cost recovery mechanism that allows Ameren Missouri to recover natural gas infrastructure replacement costs from utility
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.
Marketing Company - Ameren Energy Marketing Company, a former AER subsidiary that marketed power for Genco, AERG, and EEI. Marketing Company was included in the divestiture of New AER to IPH in December 2013. Following the New AER divestiture, Marketing Company became Illinois Power Marketing Company.
MATS -– Mercury and Air Toxics Standards, an EPA rule that limits emissionemissions of mercury and other air toxics from coalcoal- and oil-fired electric generating units.
Medina Valley -– AmerenEnergy Medina Valley Cogen, LLC, an Ameren Corporation subsidiary. This company was distributed from AER to Ameren in March 2013.
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’s portfolio of customer energy-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’s portfolio of customer energy-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.
Merchant Generation - A former financial reporting segment that, prior to the divestiture of New AER to IPH in December 2013, consisted primarily of the operations of AER, including Genco, AERG, Marketing Company and, through March 2013, Medina Valley.
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 multiyear senior unsecured credit agreement. The agreement, was amended and restatedwhich expires in December 2014 and is currently scheduled to expire on December 11, 2019.2021, unless 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. As of 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 MoPSCcosts.
electric rate order.
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 Ameren Missouri'sMEEIA 2013 customer energy efficiencyenergy-efficiency programs. This recovery mechanism was applicable to the MEEIA plan for 2013 through 2015.
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. Following the
New AER divestiture, New AER became Illinois Power Resources, LLC. Madrid Smelter – A former aluminum smelter located in southeast 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 that isare included in an Ameren Illinois recovery mechanism.
Rate base - –The net value of propertybasis 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 investment.rate 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 gas-fired energy centers in January 2014.
RTO -– Regional transmission organization.
S&P - Standard & Poor’s– S&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 current MEEIA 2016 customer energy efficiencyenergy-efficiency programs. This recovery mechanism is applicable to the MEEIA plan from March 2016 through February 2019.
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 underwithin 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, includingand changes in regulatory policies and ratemaking determinations, such as those that may result from the complaint casescase 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 appealMissouri’s proceeding with the MoPSC to pass through to customer rates the effect of the methodreduction in the federal statutory corporate income tax rate enacted under the TCJA, Ameren Illinois’ natural gas regulatory rate review filed with the ICC in January 2018, Ameren Illinois’ proceeding filed with the ICC to pass through to its natural gas customer rates the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA, the request filed by MISO participants, including Ameren Illinois and inputs usedATXI, with the FERC to calculate its performance incentiveallow revisions to 2018 electric transmission rates to reflect the impacts of the reduction in the federal statutory corporate income tax rate enacted under MEEIA for 2014 and 2015,the TCJA, and future regulatory, judicial, or legislative actions designed tothat 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, and the resulting uncertain impact on Ameren Illinois' results of operations, financial position, and liquidity;
our ability to align our overall spending, both operating and capital, with regulatory frameworks established by our regulators in an 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, tax, 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 distributedprivate 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 amount of any revenues and performance incentiveincentives earned under its MEEIA plans;
Ameren Illinois’ ability to achieve the MEEIA plans approved in August 2012FEJA electric energy-efficiency goals and February 2016 and under any future approved MEEIA plan;the resulting impact on its allowed return on program investments;
the timing of increasing capital expenditure and operating expense requirements and our ability to align overall spending, both operating and capital, with frameworks established by our regulators and to recover these costs in a timely manner;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 relating tofor Ameren Missouri’s Callaway energy center, and insurance for cyber attacks or, in the absence of insurance, the ability to recover uninsured losses from our customers;
business and economic conditions, including their impact on key customers, interest rates, collection of our receivable balances, and demand for our products;
Noranda's bankruptcy filing, the expected curtailmenteffects of operations at its aluminum smelter located in southeast Missouri,the TCJA on us and the resulting impacts to Ameren Missouri's ability to recover its revenue requirement;
revisions to Ameren Missouri’s long-term power supply agreement with Noranda, including Ameren Missouri’s notification to terminate the agreement effective June 1, 2020,treatment by regulators will have on our results of operations, financial position, and Ameren Missouri’s decision as to whether to seek MoPSC approval to cease providing electricity to Noranda thereafter;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 impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance;
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 distributiontransmission and transmissiondistribution 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 fashion;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, and any related tax
implications;divestitures;
| |
| • | 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 ourAmeren 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'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 utility 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;time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.
PART I
GENERAL
Ameren, formed in 1997 and headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. Ameren was formed in 1997 by the merger of Ameren Missouri and CIPSCO Inc., which was the parent company of CIPS. Ameren acquired CILCORP Inc., which was the parent company of CILCO, in 2003 and IP in 2004. CIPS, CILCO, and IP were merged to form Ameren Illinois in 2010. Ameren’swhose primary assets are its equity interests in its subsidiaries, including Ameren Missouri and Ameren Illinois.subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries.
Below is a summary description of Ameren’s principal subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. Ameren Illinois.also has 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 transmission and distribution business in Missouri.
Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas transmission and distribution businesses in Illinois.
Ameren has various other subsidiaries that conduct activities such as the provision of shared services. Ameren also has a subsidiary, ATXI that 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. Ameren is also pursuing projects, to improve electric transmission system reliability within Ameren Missouri's and Ameren Illinois'placed the Spoon River project in service territories as well as competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO.in February 2018.
In December 2013, Ameren completed the divestiture of New AER to IPH. In January 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. In addition, in 2013, Ameren abandoned the Meredosia and Hutsonville energy centers upon the completion of the divestiture of New AER to IPH. Ameren is demolishing the Hutsonville energy center and expects to demolish the Meredosia energy center beginning in 2016. As a result of these events, Ameren has segregated the operating results, assets, and liabilities for New AER and for the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise stated, the following information presented in Part I, Item 1, of this report excludes discontinued operations for all periods presented. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information.
The following table presents our total employees at December 31, 2015:2017:
|
| | |
| Ameren Missouri | 3,7733,639 |
|
| Ameren Illinois | 3,3053,423 |
|
| Ameren Services | 1,4491,553 |
|
| Ameren | 8,5278,615 |
|
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, 2015, the IBEW, the IUOE, the LIUNA, and the UA2017, these labor unions collectively represented about 54%52% of Ameren’s total employees. They represented 63%62% and 59%57% of the employees at Ameren Missouri and Ameren Illinois, respectively. The collective bargaining agreements have terms ranging from two to six years and expire between 20162018 and 2018.2020.
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
Ameren has two reportablefour segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois. Ameren Missouri and Ameren Illinois each have one reportable segment.Transmission. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all the operations of Ameren Missouri. The Ameren Illinois segment for both Ameren and Ameren Illinois consists of all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. SeeAmeren 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’ reporting structures is provided below. For additional information on financial reporting segments, see Note 1 – Summary of Significant Accounting Policies and Note 1715 – Segment Information under Part II, Item 8, of this report for additional information on reporting segments.
report.
| |
| (a) | Ameren Transmission segment includes associated Ameren (parent) interest charges, Ameren Transmission Company, LLC, ATX East, LLC, and ATX Southwest, LLC. |
RATES AND REGULATION
Rates
The rates that Ameren Missouri, Ameren Illinois, and ATXI are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to customers are determined by governmental entities, including the MoPSC, the ICC, and the FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the prudency of expenditures, the quality of service, regulatory staff knowledge and experience, customer intervention, and economic conditions, as well as social and political views. Decisions made by these governmental entities regarding rates are largely outside of our control. These decisions, as well as the regulatory lag involved in filing andthe 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 FERC-regulated electric transmissionAmeren Transmission and Ameren Illinois electric distribution jurisdictionsElectric Distribution businesses experiencing the least amount of regulatory lag. Depending on the jurisdiction, the effects of regulatory lag are mitigated through a variety ofby various means, including the use of a future test year, the implementation of trackers and riders, the level and timing of expenditures, and by 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 itsATXI’s rates. The FERC regulates Ameren Missouri's,Missouri’s, Ameren Illinois'Illinois’, and ATXI'sATXI’s cost-based rates for the wholesale distributiontransmission and transmissiondistribution 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, 2016:
| | | | Regulator | Allowed
Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren's 2015 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 | 56% | 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 | 9.14% | 50.0% | $2.5 | 25% | ICC | 8.40% | 50.0% | $2.7 | 25% |
Natural gas delivery service(f) | ICC | 9.60% | 50.0% | $1.2 | 13% | ICC | 9.60% | 50.0% | $1.2 | 12% |
Electric transmission delivery service(g) | FERC | 12.38% | 51.9% | $1.2 | 3% | |
Electric transmission service(g) | | FERC | 10.82% | 51.6% | $1.6 | 4% |
| ATXI | | |
Electric transmission delivery service(g) | FERC | 12.38% | 56.1% | $0.9 | 1% | |
Electric transmission service(g) | | FERC | 10.82% | 56.2% | $1.3 | 3% |
| |
| (a) | Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and natural gas purchased for resale for natural gas delivery service, and intercompany eliminations. |
| |
| (b) | Ameren Missouri'sMissouri’s electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate. |
| |
| (c) | Based on the MoPSC's April 2015MoPSC’s March 2017 rate order. This rate order specified that an implicit return on equity was within a range of 9.2% to 9.7%. The rate order did not specify a percent of common equity or rate base. The return on equity used for allowance for equity funds used during construction is 9.53%. |
| |
| (d) | Based on the MoPSC'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. |
| |
| (e) | Based on the ICC'sICC’s December 20152017 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The December 20152017 rate order was based on 20142016 recoverable costs, expected net plant additions for 2015,2017, and the monthly yields during 20142016 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois' 2016Illinois’ 2018 electric distribution delivery service revenues will be based on its 20162018 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. |
| |
| (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. |
| |
| (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 12.38%10.82% return, iswhich includes the subject of two50 basis points incentive adder for participation in an RTO, could be lowered by a FERC complaint proceedingsproceeding filed in February 2015 that are challengingchallenged the allowed return on common equity for MISO transmission owners and wouldwill require customer refunds to be issued.if the FERC approves a return on equity lower than that previously collected through rates. |
Ameren Missouri
Electric
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, all of 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.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. As of 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. 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 Noranda.
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 futuresubsequent 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 delivery service. The transmission rate is updatedupdate 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, the MoPSC includesbundled retail rates include an amount for transmission-related costs and revenues in bundled retail rates.
Natural Gasrevenues.
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, while its electric transmission delivery service operating revenues are regulated by the FERC.ICC. In 2015,2017, Ameren Illinois'Illinois’ electric distribution delivery service revenues accounted for 91% 88%of itsAmeren Illinois’ total electric operating revenues. The remainder related to electric transmission delivery service.
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 average for the calendar year average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois' actual return on equity relating to electric delivery service is subject to a collar adjustment on earnings in excess of 50 basis points greater or less than its allowed return. 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 along with the collar adjustment, if necessary, will be collected from, or refunded to, customers within the next two years.
The FEJA revised certain portions of the IEIMA, extending the IEIMA formula ratemaking framework through 2022, and clarifying that a common equity ratio up to and including 50% is prudent. Beginning in 2017, the FEJA allowed Ameren Illinois to recover, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This portion of the law extends beyond the end of the IEIMA in 2022. Through 2022, revenue differences will be included in the annual IEIMA revenue requirement reconciliation. Additionally, this law implemented a customer surcharge relating to certain nuclear energy centers located in Illinois. The surcharge, like the cost of power purchased by Ameren Illinois on behalf of its customers, will be passed through to electric distribution customers with no effect on Ameren Illinois’ earnings.
Pursuant to the FEJA, and consistent with the energy-efficiency plan for 2018 through 2021 approved by the ICC, Ameren Illinois plans to invest up to $99 million in electric energy-efficiency programs per year. Ameren Illinois plans to make additional investments of a similar level in electric energy-efficiency programs per year that will earn a return through 2030. The electric energy-efficiency program investments and the return on those investments will be collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework.
Ameren Illinois is also subject to performance standards 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 in 2016 through 2018, and up to 38 basis points in each year from 2019 through 2022, if thethese performance standards are not met. The current formula ratemaking process is effective untilBeginning in 2018, the endregulatory framework applicable to electric energy-efficiency investments provides for increases or decreases of 2019, withup 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 further extension possible through 2022.historical period relative to energy savings goals.
Under the IEIMA, Ameren Illinois is also subject to minimum capital spending levels. Between 2012 and 2021, Ameren Illinois is required to invest a minimum of $625 million in capital projects to modernize its distribution system incremental to its average annual electric deliverydistribution service capital project investmentsprojects of $228 million for calendar years 2008 through 2010, on capital projects to modernize its distribution system. Through 2015,2010. From 2012 through 2017, Ameren Illinois has invested $277$508 million in IEIMA capital projects toward its $625 million requirement. As required by the IEIMA, Ameren Illinois met the job creation requirements during the peak program year.
Ameren Illinois employs cost recovery mechanisms for power procurement, customer energy efficiency programs,energy-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 is a member of MISO and its transmission rate is calculated in accordance with the MISO OATT. Currently, the FERC-allowed return on common equity in the ratemaking formula for MISO transmission owners is 12.38%. However, the 12.38% return is subject to a November 2013 complaint case and a February 2015 complaint case that challenge the allowed return on common equity for MISO transmission owners. In December 2015, an administrative law judge issued an initial decision in the November 2013 complaint case that would lower the allowed base return on common equity to 10.32% and would require customer refunds to be issued for the 15-month period ending in February 2015. Ameren Illinois has received FERC approval to use a company-specific, forward-looking rate formula framework in setting its 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 actual sales volumes, is used to adjust billing rates in a subsequent year. In Illinois, the AMIL pricing zone transmission rate is charged directly to wholesale customers and to alternative retail electric suppliers, which serve unbundled retail load. The AMIL pricing zone transmission rate and other MISO-related costs are collected through a rider mechanism in Ameren Illinois' retail distribution tariffs from retail customers who have not chosen an alternative retail electric supplier.
Natural Gas
Ameren Illinois’ natural gas operating revenues are subject to regulationregulated 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, that was based on a 2016 future test year. In addition, theThe 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, then Ameren Illinois’ natural gas rates may be adjusted without a traditional rate proceeding.proceeding, as PGA clauses permit prudently incurred natural gas costs to be passed directly to customers. Also, Ameren Illinois employs cost recovery mechanisms for customer energy efficiency programs,energy-efficiency program costs, certain environmental costs, and bad debt expenses not recovered in base rates.
In July 2013,Illinois has a state law was enacted, whichthat encourages Illinois natural gas utilities to accelerate modernization of the state'sstate’s natural gas infrastructure. The law allows natural gas utilities to file forinfrastructure through a QIP rider. AWithout legislative action, the QIP rider will expire in December 2023. Ameren 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 received ICC approval for itsIllinois’ 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 January 2015base rates and subsequently began including qualified investmentsthe QIP rider will be reset to zero, which mitigates the risk that the QIP rider will exceed its statutory limitations in future years and recording revenue under this regulatory framework.ensures timely recovery of capital investment.
ATXIAmeren Illinois Transmission
Ameren Illinois’ transmission operating revenues are regulated by the FERC. In 2017, Ameren Illinois’ transmission service operating revenues accounted for 12% of Ameren Illinois’ electric operating revenues. See Ameren Transmission below for additional information regarding Ameren Illinois’ transmission business.
Ameren Transmission
Ameren Transmission is primarily composed of the aggregated electric transmission businesses of Ameren Illinois and ATXI. Both Ameren Illinois and ATXI is a memberare members of MISO, and itstheir transmission rate isrates are calculated in accordance with the MISO OATT. Accordingly, like Ameren Illinois ATXI's transmission rate is subject to the November 2013 and February 2015 complaint cases that challenge the allowed return on common equity for MISO transmission owners. ATXI hashave received FERC approval to use a company-specific, forward-looking rate formula ratemaking framework in setting itstheir 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. Additionally,Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues.
The FERC-allowed return on common equity for MISO transmission owners of 12.38% was challenged by customer groups in two complaint cases filed in November 2013 and in February 2015. As a result of a FERC order issued in the November 2013 complaint case, a 10.82% total allowed return on common equity has been reflected in rates since September 2016, inclusive of the 50 basis point adder for participation in an RTO. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case. If approved by the FERC, it would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. It would also require
customer refunds, with interest, for that 15-month period. A final FERC order would also establish the allowed return on common equity that will apply prospectively from the effective date of such order, replacing the current 10.82% total return on common equity.In September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. The FERC is under no deadline to issue a final order in the February 2015 complaint case.
ATXI has three MISO-approved multi-value projects, the Illinois Rivers, Spoon River, and Mark Twain projects. As of December 31, 2017, ATXI’s expected remaining investment in all three projects was approximately $300 million, with the total investment expected to be more than $1.6 billion. The Illinois Rivers project involves the construction of a 345-kilovolt line from eastern Missouri across Illinois to western Indiana. ATXI has obtained a certificate of public convenience and necessity and project approvals from the ICC and the MoPSC for each state’s portion of the Illinois Rivers project. The last line segment of this project is expected to be completed by the end of 2019; however, delays associated with property acquisition could delay the completion date. As of December 31, 2017, all 10 substations and seven of the nine line segments for Illinois Rivers were complete and in-service. The Spoon River project is located in northwest Illinois. ATXI placed the Spoon River project in service in February 2018. The Mark Twain project is located in northeast Missouri and connects Iowa to the Illinois Rivers project. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to complete the Mark Twain project by the end of 2019.
The FERC has approved transmission rate incentives relating to the three MISO-approved multi-value projects, 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 being developed by ATXI are the Illinois Rivers, Spoon River, and Mark Twain projects. The first project, Illinois Rivers, involves the construction of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. ATXI has obtained a certificate of public convenience and necessity and project approval from the ICC and the MoPSC for each state's portion of the Illinois Rivers project. The last section of this project is expected to be completed in 2019. The Spoon River project is located in northwest Illinois, and the Mark Twain project is located in northeast Missouri; each of these projects involves the construction of 345-kilovolt lines and one new substation. In September 2015, the ICC granted ATXI a certificate of public convenience and necessity and project approval for the Spoon River project. In June 2015, ATXI made a filing with the MoPSC requesting a certificate of public convenience and necessity for the Mark Twain project. A decision is expected from the MoPSC
in 2016. These two projects are expected to be completed in 2018. The total investment by ATXI in all three projects is expected to be more than $1.6 billion.
For additional information on Ameren Missouri, Ameren Illinois, and ATXI rate matters, including the MoPSC's February 2016 MEEIA order, Noranda's usage reduction and bankruptcy filing, and the FERC complaint casescase 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. In March 2015, the NRC extendedThe license for the Callaway energy center's operating license from 2024 tocenter 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 several environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for certain companies, including Ameren Missouri, that operatewhich operates coal-fired power plants. Significant new rulesAs of December 31, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the 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 require 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; new effluent standards applicable to wastewater discharges from power plants and new regulationsare regulated under the Clean Water Act thatAct. Such regulation could require significant capital expenditures, such as modifications to water intake structures or new cooling towersmore 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 new regulations are beingindividual 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, individually or the combined effects of newexisting environmental regulations could result in significant capital expenditures, and increased operating costs, for Ameren and Ameren Missouri. Compliance with all of 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 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 in
be subject to regulatory lag. These new and proposed environmental regulations could also impactaffect the availability of, the cost of, and the demand for power and natural gas whichthat 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, and mercury 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 AND SUPPLY OF ELECTRIC POWER
Ameren owns an integrated transmission system that is comprisedcomposed of the transmission assets of Ameren Missouri, Ameren Illinois, and ATXI. Ameren also operates two balancing authority areas: AMMO and AMIL. During 2015,2017, the peak demand was 8,0717,814 megawatts in AMMO and 8,6428,877 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 2018.2020. The previously required cost-benefit study related to Ameren Missouri is required to file a study with the MoPSC in November 2017, as it has done periodically since it began participating in MISO, that evaluates the costs and benefits of Ameren Missouri'sMissouri’s continued participation in MISO, beyond May 2018.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 the periodic cost-benefit study in 2020, based on the deferral granted by the MoPSC.
The Ameren CompaniesMissouri, 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, absence of sufficient owned generation, energy center outages, the fulfillment of renewable energy portfolio requirements, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than its generation cost.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, and more stringenttechnological 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 it is takingto 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 potential sites for natural-gas-fired generation to further diversify its generation portfolio. During 2015, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway site and has withdrawn its COL application with the NRC.storage.
Ameren Missouri filed its nonbinding integrated resource plan with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan. The integrated resource plan is a 20-year plan that supports a more fuel-diverse energy portfolio in Missouri, including coal, solar, wind, hydro, natural gas and nuclear power. The plan includes expanding renewable generation, retiring coal-fired generation as energy centers reach the end of their useful lives, continuation and expansion of the then-existing 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 for approximately 26%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 customerselectric 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. The costs are reflected in Ameren Illinois Electric Distribution’s results of operations, but do not affect Ameren Illinois Electric Distribution’s earnings, because these costs are offset by corresponding revenues. Ameren Illinois charges transmission and distribution service rates to electric distribution customers who purchase electricity from alternative retail electric suppliers.suppliers, which does affect Ameren Illinois Electric Distribution’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’s primary fuel source), nuclear, and natural gas, as well as renewable sources of generation, which include hydroelectric, methane gas, and solar. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978. The following table presents the sourceCallaway nuclear energy center began operation in 1984 and is licensed to operate until 2044. As of Ameren'sDecember 31, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri'sMissouri’s rate base, respectively. See Item 2 – Properties under Part I of this report for information regarding Ameren Missouri’s electric generation excluding purchased power, for the years ended December 31, 2015, 2014, and 2013:energy centers.
|
| | | | | | | |
| | Coal | | Nuclear | | Natural Gas/Oil | | Renewables(a) |
| 2015 | 71% | | 25% | | (b) | | 4% |
| 2014 | 76 | | 21 | | (b) | | 3 |
| 2013 | 77 | | 20 | | (b) | | 3 |
| |
(a) | Renewable power generation includes production from Ameren Missouri's hydroelectric, methane gas, and solar energy centers, but it excludes purchased renewable energy credits. |
| |
(b) | Less than 1% of total fuel supply. |
The following table presents the cost of fuels for electric generation for the years ended December 31, 2015, 2014, and 2013:
|
| | | | | | | | | | | |
Cost of Fuels (dollars per mmbtu) | 2015 | | 2014 | | 2013 |
Coal(a) | $ | 2.193 |
| | $ | 2.151 |
| | $ | 2.050 |
|
Nuclear(b) | 0.928 |
| | 0.918 |
| | 0.942 |
|
Natural gas(c) | 7.422 |
| | 11.226 |
| | 7.907 |
|
Weighted average – all fuels(d) | $ | 1.910 |
| | $ | 1.936 |
| | $ | 1.874 |
|
| |
(a) | The cost of coal and the costs for transportation, which include hedges for railroad diesel fuel surcharges. |
| |
(b) | The cost of uranium and its processing to become nuclear fuel. |
| |
(c) | The cost of natural gas and fixed and variable costs for transportation, storage, balancing, and fuel losses for delivery to the energy center. |
| |
(d) | All costs, including transportation, for fuels used in our energy centers, including coal, nuclear, natural gas, methane gas, and oil. Methane gas and oil are not individually listed in this table because their use is minimal. |
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 and to transport it toits energy centers. MostAs of December 31, 2017, Ameren Missouri'sMissouri had price-hedged 88% of its expected coal supply agreements expire at the endand 99% of 2017, and its existing coal transport agreements expire at the end of 2019.transportation requirements for generation in 2018. Ameren Missouri has additional coal supply contracts in place to provide a portion of itsunder contract through 2021. The coal supply in 2018.transport agreements that Ameren Missouri has coal transport agreements with Union Pacific Railroad and Burlington Northern Santa Fe Railway. AsRailway are currently set to expire at the end of December 31, 2015, Ameren Missouri had price-hedged 100% of its expected coal supply and coal transportation requirements for generation in 2016.2019. Ameren Missouri burned 18approximately 18.6 million tons of coal in 2015.2017.
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. InventoryInventories 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, 2015,2017, 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 usable 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 November 2014.December 2017. The next refuelings arerefueling is scheduled for the spring of 2016 and the fall of 2017.2019. As of December 31, 2015,2017, Ameren Missouri hashad agreements or inventories to price-hedge 100%all of Callaway's 2016Callaway’s spring 2019 refueling requirements. Ameren Missouri has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at least through 2018.the 2022 refueling. Ameren Missouri has enriched uranium inventories and enrichment supply contracts sufficient to satisfy enrichment requirements through at least 2020 and 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, 2015,2017, Ameren Missouri had price-hedged about 22%73% of its expected natural gas supply requirements for generation in 2016.2018.
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 11.5% by June 1, 2016, and to 25% by June 1, 2025. For the 2015 plan year, Ameren Illinois met its requirement that 10% of its total electricity for eligible retail customers be procured from renewable energy resources. Approximately 77% of the 2016 plan year renewable energy requirement is expected to be met through long-term agreements that Ameren Illinois has entered into to obtain renewable energy credits through 2032. The remaining requirement will be met through previous IPA procurements of additional renewable energy credits and an IPA procurement scheduled for spring 2016.
In Missouri, utilities are required to purchase or generate electricity equal to at least 2%5% of native load sales from renewable energy sources with thatbeginning in 2017. 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 2015,2017, 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
through the purchase of by purchasing solar-generated renewable energy credits from customer-installed systems and fromby generating its own solar generation fromenergy 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.
UnderState law required renewable energy resources to equal or exceed 13% of the same Missouri statutetotal electricity that requires utilitiesAmeren Illinois supplied to purchase or generate electricity fromits eligible retail customers for the twelve months ended June 1, 2017. For the 2017 plan year, Ameren Illinois met the renewable sources,energy requirement. Starting June 1, 2017, Ameren Missouri wasIllinois 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 a rebate program to provide an incentiverebates for customers to install solar generation on their premises. In accordance withcertain net metering customers. The cost of the statute and a 2013 MoPSC order, Ameren Missouri was required to provide $92 million of solar rebates by 2020, which has been substantially fulfilled. In its 2013 order, the MoPSC also authorized Ameren Missouri to employ a tracker to record the costs it incurred under its solar rebate programare deferred as a regulatory asset. Ameren Missouri is recoveringIt will be included in rate base and earn a return based on the costsutility’s weighted-average cost of capital. Customers that receive these rebates along withwill be allowed to net their supply service charges, but not their distribution service charges. Beginning in 2017, the estimated $9 millionFEJA decoupled the electric distribution revenues established in carrying cost ofa rate proceeding from the regulatory asset, over a three-year period beginningactual sales volumes, which ensures that Ameren Illinois’ electric distribution earnings will not be affected by any reduction in June 2015.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.
In August 2012, the MoPSC approved Ameren Missouri’s customer energy efficiency programs, net shared benefits, and performance incentive for 2013 through 2015. From 2013 through 2015, Ameren Missouri invested $134 million in customer energy efficiency programs and realized $174 million of net shared benefits. The MoPSC also established a performance incentive that would give Ameren Missouri the potential to earn additional revenues by achieving certain customer energy efficiency goals, including $19 million if 100% of the goals were achieved during the three-year period, with the potential to earn a larger performance incentive if Ameren Missouri's energy savings exceeded those goals.
In June 2015, the MoPSC staff filed a complaint case with the MoPSC regarding the method and inputs used in calculating the performance incentive for 2014 and 2015. In November 2015, the MoPSC issued an order that adopted the MoPSC staff’s method and inputs used in calculating the performance incentive for 2014 and 2015. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District. If the Missouri Court of Appeals upholds the MoPSC order, the performance incentive from the 2014 and 2015 MEEIA programs will be significantly less than the performance incentive calculated using Ameren Missouri’s interpretation.
In February 2016, the MoPSC issued an order approving
customer energy-efficiency programs along with a rider to collect the program costs, the throughput disincentive, and a performance incentive from customers. The throughput disincentive recovery replaced the net shared benefits that were collected under the MEEIA 2013 plan. The MEEIA rider allows Ameren Missouri's MarchMissouri 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, are reconciled annually to actual results. Ameren Missouri intends to invest $158 million in MEEIA 2016 customer energy-efficiency programs. In addition, similar to February 2019the MEEIA plan. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report2013 plan, the MoPSC’s order included a performance incentive that provides for additional information.revenues if certain MEEIA 2016 customer energy-efficiency goals are achieved, including $27 million if 100% of the goals are achieved during the three-year period. Ameren Missouri must achieve at least 25% of its energy efficiency-goals to be eligible for a MEEIA 2016 performance incentive, and can earn more if its energy savings exceed those goals.
State law requires Ameren Illinois to offer customer energy efficiencyenergy-efficiency programs. The law also allows for recovery ofIn September 2017, the programs’ costs. 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. The order authorized electric and natural gas energy-efficiency program expenditures of $394 million and $62 million, respectively, for the period 2018 through 2021. Additionally, as part of its IEIMA capital project investments, Ameren Illinois expects to invest $360$439 million in smart gridsmart-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-efficiency programs as they were incurred. Since June 2017, the FEJA has allowed Ameren Illinois to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset, and such investments will earn a return at the company’s weighted-average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. The FEJA also increased the level of electric energy-efficiency saving targets through 2030. Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs through 2030. The ICC can lower the electric energy-efficiency saving goals if sufficient cost-effective measures are not available. The electric energy-efficiency program investments and the return on those investments will be recovered through a rider; they will not be included in the IEIMA formula rate process.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their utility 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, 2015,2017, Ameren Missouri had price-hedged 75% and Ameren Illinois had price-hedged 97%66% and 75%, respectively, of their expected 20162018 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;
changes to corporate income tax law changes that accelerate depreciation deductions, which reduce currentas a result of the enactment of the TCJA, as well as additional interpretations, regulations, amendments, or technical corrections related to the federal income tax paymentscode, and improve cash flow, but also result in rate base reductions and limit the ability to claim other deductions and use carryforwardany state income tax benefits;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 those customersthem both to both 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 transmission assets;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;
the likelya further 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 qualified labor and material, and rising costs;
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 flows,flow, which is defined as cash flows from operating activities less cash flows from investing activities and dividends paid;
public concernconcerns 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 thatat which electric generating units are dispatched based upon their CO2 emissions; |
public concernconcerns about the potential environmental impacts to the environment from the combustion of fossil fuels;fuels and some investors’ concerns about investing in energy companies that have fossil fuel-fired generation assets;
aging infrastructure and the need to construct new power generation, transmission, and distribution facilities, which have long time frames for completion, with littlelimited long-term ability to predict power and commodity prices, and regulatory requirements;
legislation or proposals for programs to encourage or mandate energy efficiency and renewable sources of power, such as solar, and the debate over who should pay for those programs;
public concernconcerns 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, | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Electric Sales – kilowatthours (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | 12,903 |
| | 13,649 |
| | 13,562 |
| 12,653 |
| | 13,245 |
| | 12,903 |
|
| Commercial | 14,574 |
| | 14,649 |
| | 14,634 |
| 14,384 |
| | 14,712 |
| | 14,574 |
|
| Industrial | 8,273 |
| | 8,600 |
| | 8,709 |
| 4,469 |
| | 4,790 |
| | 8,273 |
|
| Street lighting and public authority | | 117 |
| | 125 |
| | 126 |
|
| Ameren Missouri retail load subtotal | | 31,623 |
| | 32,872 |
| | 35,876 |
|
| Off-system | 7,380 |
| | 6,170 |
| | 6,128 |
| 10,640 |
| | 7,125 |
| | 7,380 |
|
| Other | 126 |
| | 124 |
| | 125 |
| |
| Ameren Missouri total | 43,256 |
| | 43,192 |
| | 43,158 |
| 42,263 |
| | 39,997 |
| | 43,256 |
|
| Ameren Illinois: | | | | | | |
Ameren Illinois Electric Distribution(a): | | | | | | |
| Residential | | | | | | 10,985 |
| | 11,512 |
| | 11,554 |
|
| Power supply and delivery service | 4,797 |
| | 4,662 |
| | 5,474 |
| |
| Delivery service only | 6,757 |
| | 7,222 |
| | 6,310 |
| |
| Commercial | | | | | | 12,382 |
| | 12,583 |
| | 12,280 |
|
| Power supply and delivery service | 2,837 |
| | 2,535 |
| | 2,606 |
| |
| Delivery service only | 9,443 |
| | 9,643 |
| | 9,541 |
| |
| Industrial | | | | | | 11,359 |
| | 11,738 |
| | 11,863 |
|
| Power supply and delivery service | 1,589 |
| | 1,674 |
| | 1,613 |
| |
| Delivery service only | 10,274 |
| | 10,576 |
| | 10,861 |
| |
| Other | 524 |
| | 518 |
| | 522 |
| |
| Ameren Illinois total | 36,221 |
| | 36,830 |
| | 36,927 |
| |
| Street lighting and public authority | | 515 |
| | 521 |
| | 524 |
|
| Ameren Illinois Electric Distribution total | | 35,241 |
| | 36,354 |
| | 36,221 |
|
| Eliminate affiliate sales | (385 | ) | | (67 | ) | | (82 | ) | (440 | ) | | (520 | ) | | (385 | ) |
| Ameren total | 79,092 |
| | 79,955 |
| | 80,003 |
| 77,064 |
| | 75,831 |
| | 79,092 |
|
| Electric Operating Revenues (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | $ | 1,464 |
| | $ | 1,417 |
| | $ | 1,428 |
| $ | 1,416 |
| | $ | 1,421 |
| | $ | 1,464 |
|
| Commercial | 1,258 |
| | 1,203 |
| | 1,216 |
| 1,207 |
| | 1,223 |
| | 1,258 |
|
| Industrial | 469 |
| | 475 |
| | 491 |
| 305 |
| | 315 |
| | 469 |
|
| Other, including street lighting and public authority | | 115 |
| | 102 |
| | 84 |
|
| Ameren Missouri retail load subtotal | | $ | 3,043 |
| | $ | 3,061 |
| | $ | 3,275 |
|
| Off-system | 195 |
| | 173 |
| | 183 |
| 370 |
| | 333 |
| | 195 |
|
| Other | 84 |
| | 120 |
| | 61 |
| |
| Ameren Missouri total | $ | 3,470 |
| | $ | 3,388 |
| | $ | 3,379 |
| $ | 3,413 |
| | $ | 3,394 |
| | $ | 3,470 |
|
| Ameren Illinois: | | | | | | |
| Ameren Illinois Electric Distribution: | | | | | | |
| Residential | | | | | | $ | 870 |
| | $ | 894 |
| | $ | 858 |
|
| Power supply and delivery service | $ | 495 |
| | $ | 468 |
| | $ | 501 |
| |
| Delivery service only | 363 |
| | 308 |
| | 282 |
| |
| Commercial | | | | | | 527 |
| | 518 |
| | 474 |
|
| Power supply and delivery service | 247 |
| | 233 |
| | 215 |
| |
| Delivery service only | 227 |
| | 185 |
| | 184 |
| |
| Industrial | | | | | | 113 |
| | 96 |
| | 124 |
|
| Power supply and delivery service | 71 |
| | 87 |
| | 68 |
| |
| Delivery service only | 53 |
| | 42 |
| | 44 |
| |
| Other | 227 |
| | 199 |
| | 167 |
| |
| Ameren Illinois total | $ | 1,683 |
| | $ | 1,522 |
| | $ | 1,461 |
| |
| ATXI: | | | | | | |
| Transmission services | $ | 70 |
| | $ | 33 |
| | $ | 19 |
| |
| Other and intercompany eliminations | (43 | ) | | (30 | ) | | (27 | ) | |
| Other, including street lighting and public authority | | 58 |
| | 41 |
| | 76 |
|
| Ameren Illinois Electric Distribution total | | $ | 1,568 |
| | $ | 1,549 |
| | $ | 1,532 |
|
| Ameren Transmission: | | | | | | |
Ameren Illinois Transmission(b) | | $ | 258 |
| | $ | 232 |
| | $ | 189 |
|
| ATXI | | 168 |
| | 123 |
| | 70 |
|
| Ameren Transmission total | | $ | 426 |
| | $ | 355 |
| | $ | 259 |
|
| Other and intersegment eliminations | | (97 | ) | | (102 | ) | | (81 | ) |
| Ameren total | $ | 5,180 |
| | $ | 4,913 |
| | $ | 4,832 |
| $ | 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 2015, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution. |
| | Electric Operating Statistics – Year Ended December 31, | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Electric Generation – Ameren Missouri – kilowatthours (in millions) | 42,424 |
| | 43,474 |
| | 43,213 |
| |
| Price per ton of delivered coal (average) – Ameren Missouri | $ | 37.88 |
| | $ | 37.36 |
| | $ | 36.19 |
| |
| Source of Ameren Missouri energy supply: | | | | | | | | | | |
| Coal | 67.1 | % | | 73.5 | % | | 74.1 | % | 70.9 | % | | 66.2 | % | | 67.1 | % |
| Nuclear | 23.3 |
| | 20.6 |
| | 18.6 |
| 19.0 |
| | 22.8 |
| | 23.3 |
|
| Hydroelectric | 3.6 |
| | 2.2 |
| | 2.9 |
| 3.4 |
| | 3.3 |
| | 3.6 |
|
| Natural gas | 0.3 |
| | 0.2 |
| | 0.4 |
| 0.7 |
| | 0.7 |
| | 0.3 |
|
| Methane gas and solar | 0.2 |
| | 0.1 |
| | 0.1 |
| 0.1 |
| | 0.1 |
| | 0.2 |
|
| Purchased – Wind | 0.7 |
| | 0.8 |
| | 0.7 |
| 0.7 |
| | 0.8 |
| | 0.7 |
|
| Purchased – Other | 4.8 |
| | 2.6 |
| | 3.2 |
| 5.2 |
| | 6.1 |
| | 4.8 |
|
| | 100.0 | % | | 100.0 | % | | 100.0 | % | |
| Ameren Missouri total | | 100.0 | % | | 100.0 | % | | 100.0 | % |
| | Gas Operating Statistics – Year Ended December 31, | 2015 | | 2014 | | 2013 | |
Natural Gas Operating Statistics – Year Ended December 31, | | 2017 | | 2016 | | 2015 |
| Natural Gas Sales – dekatherms (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | 7 |
| | 8 |
| | 8 |
| 6 |
| | 6 |
| | 7 |
|
| Commercial | 3 |
| | 4 |
| | 4 |
| 3 |
| | 3 |
| | 3 |
|
| Industrial | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
| Transport | 7 |
| | 7 |
| | 6 |
| 8 |
| | 8 |
| | 7 |
|
| Ameren Missouri total | 18 |
| | 20 |
| | 19 |
| 18 |
| | 18 |
| | 18 |
|
| Ameren Illinois: | | | | | | |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | 55 |
| | 66 |
| | 62 |
| 50 |
| | 52 |
| | 55 |
|
| Commercial | 18 |
| | 23 |
| | 21 |
| 15 |
| | 17 |
| | 18 |
|
| Industrial | 3 |
| | 3 |
| | 6 |
| 3 |
| | 3 |
| | 3 |
|
| Transport | 89 |
| | 91 |
| | 87 |
| 98 |
| | 94 |
| | 89 |
|
| Ameren Illinois total | 165 |
| | 183 |
| | 176 |
| |
| Ameren Illinois Natural Gas total | | 166 |
| | 166 |
| | 165 |
|
| Ameren total | 183 |
| | 203 |
| | 195 |
| 184 |
| | 184 |
| | 183 |
|
| Natural Gas Operating Revenues (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | $ | 84 |
| | $ | 102 |
| | $ | 102 |
| $ | 77 |
| | $ | 77 |
| | $ | 84 |
|
| Commercial | 34 |
| | 40 |
| | 42 |
| 31 |
| | 30 |
| | 34 |
|
| Industrial | 5 |
| | 7 |
| | 8 |
| 4 |
| | 4 |
| | 5 |
|
| Transport and other | 14 |
| | 15 |
| | 9 |
| 14 |
| | 17 |
| | 14 |
|
| Ameren Missouri total | $ | 137 |
| | $ | 164 |
| | $ | 161 |
| $ | 126 |
| | $ | 128 |
| | $ | 137 |
|
| Ameren Illinois: | | | | | | |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | $ | 550 |
| | $ | 675 |
| | $ | 611 |
| $ | 532 |
| | $ | 531 |
| | $ | 550 |
|
| Commercial | 163 |
| | 208 |
| | 185 |
| 146 |
| | 153 |
| | 163 |
|
| Industrial | 13 |
| | 23 |
| | 26 |
| 14 |
| | 12 |
| | 13 |
|
| Transport and other | 57 |
| | 70 |
| | 25 |
| 51 |
| | 58 |
| | 57 |
|
| Ameren Illinois total | $ | 783 |
| | $ | 976 |
| | $ | 847 |
| |
| Ameren Illinois Natural Gas total | | $ | 743 |
| | $ | 754 |
| | $ | 783 |
|
| Other and intercompany eliminations | (2 | ) | | — |
| | (2 | ) | (2 | ) | | (2 | ) | | (2 | ) |
| Ameren total | $ | 918 |
| | $ | 1,140 |
| | $ | 1,006 |
| $ | 867 |
| | $ | 880 |
| | $ | 918 |
|
| | | | | | | |
Rate Base Statistics – At December 31, | | 2017 | | 2016 | | 2015 |
| Rate Base (in billions): | | | | | | |
| Coal generation | | $ | 2.0 |
| | $ | 2.0 |
| | $ | 2.0 |
|
| Natural gas generation | | 0.4 |
| | 0.4 |
| | 0.5 |
|
| Nuclear and renewables generation | | 1.9 |
| | 1.8 |
| | 1.7 |
|
| Electric and natural gas transmission and distribution | | 10.1 |
| | 9.4 |
| | 8.2 |
|
| Rate base total | | $ | 14.4 |
| | $ | 13.6 |
| | $ | 12.4 |
|
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 oversight and environmentaloperations 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 extensive 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 industries are extensivelyindustry is highly regulated. The utility rates charged to our customers are determined by governmental entities, including the MoPSC, the ICC, and the FERC. Many factors influence decisionsDecisions 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 willmay 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 may beare based on historical or estimated future costs and revenues. Thus the rates that a utility iswe are allowed to charge for utility services may not match itsour 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’ incurred 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 average for 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 $6$8 million change in Ameren'sAmeren’s and Ameren Illinois'Illinois’ net income, based on its 20162018 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 year from 2016 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 minimum of $625 million in capital projects to modernize its distribution system incremental to its average annual electric deliverydistribution service capital projects investments of $228 million for calendar years 2008 through 2010,2010. Through 2017, Ameren Illinois has invested $508 million in orderIEIMA 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 modernizeannually update its distribution system.
performance-based formula rates under IEIMA.Unless extended through 2022,Without the extension of formula ratemaking, the IEIMA performance-based formula ratemaking process will expire in 2019. When itframework expires at the end of 2022. 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 facility closures,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. From the beginning phases of sitingThe development and development to the operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities our activities involvecan trigger compliance obligations with diverserespect to environmental laws and regulations. These laws and regulations address emissions;emissions, discharges to water; water, usage;water usage, impacts to air, land, and water;water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, orand 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 several environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for certain companies, including Ameren Missouri, that operatewhich operates coal-fired power plants. Significant new rulesAs of December 31, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the 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 require 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; new effluent standards applicable to wastewater discharges from power plants; and new regulationsplants are regulated under the Clean Water Act
thatAct. Such regulation could require significant capital expenditures, such as modifications to water intake structures or new cooling towersmore 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 new regulations are beingindividual 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, individually or the combined effects of newexisting 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 allegingMissouri. 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. An outcomeThe 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 then proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. 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 Ameren Missourieconomic and regulatory considerations, resolution of this matter could require substantialresult in increased capital expenditures which cannot be determined at this time. Such expenditures could also affect unit retirementfor the installation of pollution control equipment, as well as increased operations and replacement decisions.maintenance expenses.
TheIn 2015, the EPA issued the Clean Power Plan, which sets forthwould have established CO2emissions standards applicable to existing power plants, was issued by the EPA but stayed by theplants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In October 2017, the outcome of various appeals, as discussed below. IfEPA announced a proposal to repeal the Clean Power Plan is ultimately upheldPlan. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input from stakeholders as issued, Ameren Missouri expects to incur increased fuel and operating costs, and make new or accelerated capital expenditures, in addition tohow the costs of making modifications to existing operations in order to achieve compliance. The Clean Power Plan required Missouri and Illinois to reduceEPA 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 2022 that require each state to demonstrate progress in achieving its CO2 reduction target. Ameren is evaluatingunder the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation investment. Significant uncertainty exists regarding the impact ofAir Act. Accordingly, we no longer expect the Clean Power Plan as its implementation will depend upon plans to be developed bytake effect. However, the states. Numerous legal challenges are pending which could result in the rule being declared invalid or the nature and timing ofEPA may issue new requirements that would regulate CO2 emissions reductions being revised. In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until such time as legal appeals are concluded. Appeals are not expected to conclude prior to 2018.from existing power plants. We cannot predict the outcome of the 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 implemented in substantially similar form to the rule when issued, 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 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 operationoperations of its energy centers. Moreover, ifIf Ameren Missouri requests recovery of these 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 unableAny of the foregoing could have an adverse effect on our results of operations, financial positions, and liquidity.
The TCJA is complex and significantly affects the Ameren Companies. As a result of the TCJA, the Ameren Companies expect lower operating cash flows, driven by lower customer rates, which may need to predictbe funded through debt and/or equity issuances. Further, additional interpretations, regulations, amendments, and technical corrections to the ultimate impact of these matters onfederal income tax code, as well as the associated treatment by our regulators, may adversely affect our results of operations, financial position, and liquidity.
We may not be ableThe TCJA, among other things, reduced the federal statutory corporate income tax rate from 35% to fully utilize21%, effective January 1, 2018. Additionally, the TCJA eliminated 50% accelerated depreciation tax benefits for nearly all regulated utility capital investments made after September 27, 2017. As of December 31, 2017, Ameren recorded a noncash charge to earnings of $154 million as a result of the revaluation of deferred taxes, largely attributable to Ameren (parent). Ameren also reclassified deferred income tax liabilities of $2.4 billion to regulatory liabilities. This reclassification is due to the reduction of the federal statutory corporate income tax rate, which reduced such income tax obligations, and the expected return of funds previously collected from customers. Our rate-regulated businesses recover income taxes in customer rates based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds from our customers for income taxes and when we pay such taxes. Excess deferred taxes were created as the deferred income tax obligation decreased due to a reduction in the federal statutory corporate income tax rate.
The elimination of 50% accelerated tax depreciation on nearly all capital investments has caused an increase in Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion). Over the next five years, Ameren may be required to issue incremental debt and/or charitable contribution carryforwards,equity to fund this reduction in operating cash flows, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. Ameren Missouri and Ameren Illinois expect to fund cash flows needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent), with the intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. As a result of the TCJA, financial metrics used by credit rating agencies may be negatively affected, primarily due to expected decreases in operating cash flows discussed above.
Most of the effects of the TCJA will be reflected in adjusted customer electric and gas rates over time. The regulatory treatment of the effects of the TCJA will be subject to the discretion of the FERC, the MoPSC and the ICC. The period over which the return of excess deferred taxes will occur will ultimately be determined by our regulators.
Certain aspects of the TCJA are unclear. These aspects will require interpretations and regulations from the IRS and state taxing authorities, and the TCJA could be subject to potential amendments and technical corrections, any of which could adversely affect our results of operations, financial position, and liquidity.
We have significantly reduced our consolidated federal and state 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 obligations in the past through tax planning strategies. Additionally, our consolidated income tax obligations have been reduced due to the continued usereturn, either of bonus depreciation provisions that allow for an acceleration of deductions for tax purposes and recent IRS guidance on tax deductions for repairs. We estimate our ability to use tax benefits, including those in the form of net operating loss, tax credit and charitable contribution carryforwards, that are recorded as deferred tax assets on our balance sheets. A disallowance of these tax benefits resulting from a legislative change or adverse determination by one of the applicable taxing jurisdictionswhich could have an adverse impact onadversely affect our results of operations, financial position, and liquidity. Additionally, changesThere may be other material adverse effects resulting from the TCJA that we have not yet identified, each of which could be material in corporate income tax rate or policy changes as well as any inability to generate enough taxable income in the future to use all of our tax benefits before they expire could have an adverse impact on our results of operations, financial position, and liquidity.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 or facilities as a result of severe or destructive weather or other causes, and thecauses. The ability of Ameren Missouri and Ameren Illinois to respond promptly respond 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 the proliferation of 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.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 FERC statutes,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, or the FERC statutes,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 has the ability toit can require retroactive 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 in order to make investments to maintain and improve our electric and natural gas utility infrastructure and to comply with existing environmental regulations. We estimate that we will incurinvest up to $11.5$11.4 billion (Ameren Missouri – up to $4.3$4.5 billion; Ameren Illinois – up to $6.2$6.6 billion; ATXI – up to $1.0$0.3 billion) of capital expenditures during 2016from 2018 through 2022. These estimates do not reflect the potential additional investments identified in Ameren Missouri’s integrated resource plan, which could represent incremental investments of approximately $1 billion through 2020 excluding the impacts of the Clean Power Plan.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 toof 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, the ability to obtain required project approvals, and environmental compliance.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. With respect to capital expenditures for pollution control equipment, thereThere 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 isare subject to change,changes, including changes as a result of third-party complaints and challenges at the FERC. The regulatory framework may not be asless favorable or the rate of return may be lower in the future. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. In November 2013, aA pending complaint case was filed with the FERC seeking a reduction in February 2015 could reduce the allowed return on common equity under the MISO tariff. In December 2015, a FERC administrative law judge issued an initial decision in the November 2013 complaint case that would lower the allowed base return on common equity to 10.32%. The FERC is expected to issue a final order on the November 2013 complaint case by October 2016. A second complaint case was filed in February 2015. The outcome of these complaint casesand could
negatively affect Ameren Illinois' and ATXI's allowed return. Any such reduction would also result in a refund of transmission service revenues earned since the filing of the initial complaint case in November 2013. As of December 31, 2015, Ameren and Ameren Illinois had current regulatory liabilities of $45 million and $32 million, respectively, representing their estimates of the potential refunds from the refund effective date. 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 $6$8 million and $3$4 million, respectively, based on each company's 2016company’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. The totalAs of December 31, 2017, ATXI’s expected remaining investment by ATXI in all three projects iswas approximately $300 million, with the total investment expected to be more than $1.6 billion.billion The last of these projects is expected to be completed in 2019. A failure by ATXI to complete these three projects on time and within projected cost estimates could adversely affect Ameren'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 outside of its subsidiaries' service territories and outside of MISO to construct electric transmission assets.
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 that affectto 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, which include the following: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;supply and our reliance on licensed fuel assemblies that are fabricated by Westinghouse, Callaway energy center’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;
costly and extended outages for scheduled or unscheduled maintenance and refueling;
the adverse effect of poor market performance and other economic factors on the asset values of nuclear decommissioning trust funds and the corresponding increase, upon MoPSC approval, in customer rates to fund the estimated decommissioning costs; and
potential adverse effects of a natural disaster, acts of sabotage or terrorism, including 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, accidental 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. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and 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 and therefore, ifstandards. Any failure to achieve these standards are not achieved, it will result in a reduction in Ameren Illinois'Illinois’ allowed return on equity.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 even if it sponsors customer energy efficiency programs under the MEEIA, is exposed to declining usage losses from energy efficiencyenergy-efficiency efforts not related to its specificenergy-efficiency programs, as well as from distributed generation sources, such as solar panels. 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. We expect that theThe costs of these distributed generation technologies willmay 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 and Ameren Illinois 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 subjectparty to collective bargaining agreements that collectively represent about 54%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 sabotage, war, 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 targets ofaffected 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, ora 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 volumethe number and sophistication of cybersecurity incidents from international activist organizations, countries, and individuals.cyber attacks across all industries worldwide. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm associated withresulting from theft or the inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected system. Therefore, a disruption caused by a cybersecuritycyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. We maintain insurance against some, butInsurance might not all, ofbe adequate to cover losses that arise in connection with these risks and losses.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 2019, $951 million and $457 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these
senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. The inability to raise debt or equity capital 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 additional 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.
Noranda's bankruptcy filing, the expected curtailment of operations at its aluminum smelter, and the resulting significant reduction in sales volumes to Noranda will adversely affect Ameren’s and Ameren Missouri’s results of operations, financial condition, and liquidity.
Ameren Missouri supplies electricity to Noranda’s aluminum smelter in southeast Missouri under a long-term power supply contract. In its April 2015 electric rate order, the MoPSC approved a rate design that established $78 million in annual revenues, net of fuel and purchased power costs, as Noranda’s portion of Ameren Missouri’s revenue requirement. The portion of Ameren Missouri’s annual revenue requirement reflected in Noranda’s electric rate is based on the assumption that the smelter will use approximately 4.2 million megawatthours annually, which is almost 100% of its operating capacity.
On January 8, 2016, Noranda announced that production had been idled at two of its three pot lines at the smelter following
an electric supply circuit failure on assets not owned by Ameren Missouri. On January 13, 2016, Noranda announced that the smelter’s “remaining operations will be curtailed on or before March 12, 2016, unless [Noranda] is able to secure a substantially more sustainable power rate for the smelter and materially improve [Noranda’s] overall liquidity.” On February 8, 2016, Noranda filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In the filing, Noranda reaffirmed that the remaining pot line will continue to operate at the smelter until March 2016, at which time operation of the line will be curtailed. Noranda stated it would maintain the flexibility to restart operations at the smelter should conditions allow.
As a result of these events in 2016, actual sales volumes to Noranda will be significantly below the sales volumes reflected in rates and therefore, Ameren Missouri will not fully recover its revenue requirement until rates are adjusted by the MoPSC in a future electric rate case to accurately reflect Noranda’s actual sales volumes. In light of the Noranda announcements described above, Ameren Missouri expects to employ a provision in its FAC tariff that, under certain circumstances, allows Ameren Missouri to retain a portion of any revenues from any off-system sales it makes as a result of the reduced tariff sales to Noranda. The current market price of electricity is less than Noranda’s electric rate, and Ameren Missouri expects market prices to remain below Noranda's electric rate during 2016. Accordingly, this FAC provision would not enable Ameren Missouri to fully recover its revenue requirement under current market conditions.
Ameren Missouri will continue to monitor Noranda’s sales volumes and evaluate its regulatory and legislative options to mitigate adverse financial impacts. The reduction in Noranda’s sales volumes will adversely affect Ameren’s and Ameren Missouri’s results of operations, financial condition, and liquidity until customer rates are adjusted in a future rate case.
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 $567$551 million as of December 31, 2015.2017. Ameren expects to fund its pension plans at a level equal to the greater of the pension expensecost or the legally required minimum contribution. ConsideringBased on Ameren’s assumptions at December 31, 2015,2017, its investment performance in 2015,2017, and its pension funding policy, Ameren expects to make annual contributions of $40less than $1 million to $70$60 million in each of the
next five years, with aggregate estimated contributions of $280 million.$120 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 40%35% and 50%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 20162018 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 | 970,000972,000 |
|
| | Meramec(b) | St. Louis County, Missouri | 591,000 |
|
| Total coal | | | 5,111,0005,113,000 |
|
| Nuclear | Callaway | Callaway County, Missouri | 1,193,0001,194,000 |
|
| Hydroelectric | Osage | Lakeside, Missouri | 240,000 |
|
| | Keokuk | Keokuk, Iowa | 140,000144,000 |
|
| Total hydroelectric | | | 380,000384,000 |
|
| 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 | 53,00054,000 |
|
| | Moberly | Moberly, Missouri | 53,00054,000 |
|
| | Moreau | Jefferson City, Missouri | 53,00054,000 |
|
| Total oil | | | 267,000272,000 |
|
| Natural gas (CTs) | Audrain(b)(c) | Audrain County, Missouri | 600,000608,000 |
|
| | Venice(c)(d) | Venice, Illinois | 487,000491,000 |
|
| | Goose Creek | Piatt County, Illinois | 432,000438,000 |
|
| | Pinckneyville | Pinckneyville, Illinois | 316,000 |
|
| | Raccoon Creek | Clay County, Illinois | 300,000304,000 |
|
| | Meramec(c)(b)(d)(e) | St. Louis County, Missouri | 282,000281,000 |
|
| | Kinmundy(c)(d) | Kinmundy, Illinois | 206,000208,000 |
|
| | Peno Creek(b)(c)(d) | Bowling Green, Missouri | 188,000 |
|
| Kirksville | Kirksville, Missouri | 13,000192,000 |
|
| Total natural gas | | | 2,824,0002,838,000 |
|
| 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 | | | 10,226,00010,252,000 |
|
| |
| (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 236,000 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. |
| |
(c)(d) | These CTs have the capability to operate on either oil or natural gas (dual fuel). |
| |
(d)(e) | Includes capabilityTwo of two coalits three units that will burn natural gas beginning in April 2016.are steam-powered. |
The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2015:2017:
| | | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois |
Circuit miles of electric transmission lines(a) | 2,957 |
| | 4,569 |
| 2,970 |
| | 4,638 |
|
| Circuit miles of electric distribution lines | 33,252 |
| | 45,881 |
| 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 | 3,330 |
| | 18,294 |
| 3,379 |
| | 18,393 |
|
| Underground gas storage fields | — |
| | 12 |
| |
| Total working capacity of underground gas storage fields in billion cubic feet | — |
| | 24 |
| |
| Underground natural gas storage fields | | — |
| | 12 |
|
| Total working capacity of underground natural gas storage fields in billion cubic feet | | — |
| | 24 |
|
| |
| (a) | ATXI owns 29303 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’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 plantequipment 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 onin December 1, 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 plantequipment 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 – CommitmentCommitments and Contingencies under Part II, Item 8, of this report and are incorporated herein by reference, include the following:
Ameren Missouri's appeal to the Missouri Court of Appeals, Western District, regarding the method and inputs used to calculate its performance incentive under MEEIA for 2014 and 2015;
ATXI’s request for a certificate of convenience and necessity fromMissouri’s proceeding with the MoPSC forto investigate how the Mark Twain project;effect of the reduction in the federal statutory corporate income tax rate enacted under TCJA should be reflected in rates paid by electric and natural gas customers;
Ameren Illinois’ proceeding with the ICC to pass through to its natural gas customers the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA;
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 rates to reflect the impacts of the reduction in the federal statutory corporate income tax rate enacted under the TCJA;
the February 2015 complaint casescase filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff;
the EPA's Clean Air Act-related litigation against Ameren Missouri;Missouri with respect to the EPA Clean Air Act; and
remediation matters associated with former MGP and waste disposal sites of the Ameren Companies;Companies.
asbestos-related litigation associated with the Ameren Companies; and
class action lawsuit against Ameren Missouri relating to municipal taxes.
| |
| 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, 20152017, all their positions and offices held with the Ameren Companies as of February 15, 2016, 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 | 5456 |
| | 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. | 4951 |
| | Executive Vice President and Chief Financial Officer |
Lyons joined Ameren Services in 2001. In 2008, Lyonshe was elected senior vice president and principalchief 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 principalchief accounting officer. Lyons has also beenIn 2016, he was elected chairman and president of Ameren Services, effective upon the retirement of Daniel F. Cole on March 1, 2016.Services. |
| | | | |
| Gregory L. Nelson | 5860 |
| | 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 | 5456 |
| | 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 | 5153 |
| | Senior Vice President, Corporate Safety, PlanningCustomer and Power Operations Oversight (Ameren Services)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. |
| | | |
Maureen A. Borkowski | 58 |
| | 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, Borkowski was elected chairman and president of ATXI. In 2011, she was also elected senior vice president, transmission, of Ameren Services. |
| | | |
Daniel F. Cole | 62 |
| | Chairman and President (Ameren Services) |
Cole joined Ameren Missouri in 1976. HeJanuary 2017, he was elected senior vice president, ofcustomer operations, at Ameren Missouri and relinquished his positions at Ameren Services in 1999 and of Ameren Illinois in 2001.Services. In 2009, ColeOctober 2017, he was elected chairman and president of Ameren Services; he remained senior vice president, ofcustomer and power operations, at Ameren Missouri and Ameren Illinois. Cole will retire from all of his positions effective March 1, 2016.Missouri. |
| | | | |
| Fadi M. Diya | 5355 |
| | 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 | 5961 |
| | 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 | 4850 |
| | 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 | 6062 |
| | 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 | 4648 |
| | 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 52,27747,748 on January 29,31, 20162018. The following table presents the price ranges, closing prices, and dividends declared per Ameren common share for each quarter during 20152017 and 20142016:
| | | | High | | Low | | Close | | Dividends Declared | High | | Low | | Close | | Dividends Declared |
| 2015 Quarter Ended: | | | | | | | | |
| 2017 Quarter Ended: | | | | | | | | |
| March 31 | $ | 46.81 |
| | $ | 40.51 |
| | $ | 42.20 |
| | $ | 0.41 |
| $ | 56.57 |
| | $ | 51.35 |
| | $ | 54.59 |
| | $ | 0.44 |
|
| June 30 | 43.00 |
| | 37.26 |
| | 37.68 |
| | 0.41 |
| 57.21 |
| | 53.72 |
| | 54.67 |
| | 0.44 |
|
| September 30 | 43.85 |
| | 37.55 |
| | 42.27 |
| | 0.41 |
| 60.91 |
| | 53.54 |
| | 57.84 |
| | 0.44 |
|
| December 31 | 44.71 |
| | 41.33 |
| | 43.23 |
| | 0.425 |
| 64.89 |
| | 57.67 |
| | 58.99 |
| | 0.4575 |
|
| 2014 Quarter Ended: | | | | | | | | |
| 2016 Quarter Ended: | | | | | | | | |
| March 31 | $ | 42.24 |
| | $ | 35.22 |
| | $ | 41.20 |
| | $ | 0.40 |
| $ | 50.16 |
| | $ | 41.50 |
| | $ | 50.10 |
| | $ | 0.425 |
|
| June 30 | 41.92 |
| | 37.67 |
| | 40.88 |
| | 0.40 |
| 53.59 |
| | 46.29 |
| | 53.58 |
| | 0.425 |
|
| September 30 | 40.96 |
| | 36.65 |
| | 38.33 |
| | 0.40 |
| 54.08 |
| | 47.79 |
| | 49.18 |
| | 0.425 |
|
| December 31 | 48.14 |
| | 38.25 |
| | 46.13 |
| | 0.41 |
| 52.88 |
| | 46.84 |
| | 52.46 |
| | 0.44 |
|
There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding common stock of Ameren Missouri and Ameren Illinois.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its registrant subsidiaries during 20152017 and 20142016:
| | | | 2015 | | 2014 | 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 | $ | 85 |
| | $ | 75 |
| | $ | 100 |
| | $ | 315 |
| | | $ | 72 |
| (a) | $ | 113 |
| | $ | 78 |
| | $ | 77 |
| $ | 30 |
| | $ | 160 |
| | $ | 112 |
| | $ | 60 |
| | | $ | 70 |
| | $ | 75 |
| | $ | 70 |
| | $ | 140 |
|
| Ameren Illinois | — |
| | — |
| | — |
| | — |
| | | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | | 15 |
| | 35 |
| | 30 |
| | 30 |
|
| Ameren | 104 |
| | 99 |
| | 100 |
| | 99 |
| | | 99 |
| | 97 |
| | 97 |
| | 97 |
| 111 |
| | 106 |
| | 107 |
| | 107 |
| | | 107 |
| | 103 |
| | 103 |
| | 103 |
|
| |
(a) | Additionally, during the fourth quarter of 2014, Ameren Missouri returned capital of $215 million to Ameren (parent). |
On February 12, 2016,9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 42.545.75 cents per share. The common share dividend is payable March 31, 2016,29, 2018, to shareholders of record on March 9, 2016.14, 2018.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.
Purchases of Equity Securities
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
|
| | | | | | | | | | | | |
| Period | (a) Total Number of Shares (or Units) Purchased(a) | | (b) Average Price Paid per Share (or Unit) | | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
| October 1 – October 31, 2015 | — |
| | $ | — |
| | — |
| | — |
|
| November 1 – November 30, 2015 | 2,277 |
| | 43.80 |
| | — |
| | — |
|
| December 1 – December 31, 2015 | — |
| | — |
| | — |
| | — |
|
| Total | 2,277 |
| | $ | 43.80 |
| | — |
| | — |
|
|
| | | | | | | | | | | | |
| 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) | TheseThe shares of Ameren common stock were purchased in open-market transactions to fundin satisfaction of Ameren’s obligations for itsAmeren board of directors’ stock compensation awards which were grantedissued under the 2014 Incentive Plan.its stock-based compensation plans. Ameren does not have any publicly announced equity securities purchaserepurchase 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, 20152017, to December 31, 20152017.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 20152017. 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, 20102012, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
| | | December 31, | 2010 | | 2011 | | 2012 | | 2013 | | 2014 | | 2015 | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| Ameren (AEE) | $ | 100.00 |
| | $ | 123.92 |
| | $ | 120.78 |
| | $ | 148.94 |
| | $ | 197.69 |
| | $ | 193.00 |
| $ | 100.00 |
| | $ | 123.31 |
| | $ | 163.67 |
| | $ | 159.79 |
| | $ | 200.79 |
| | $ | 232.84 |
|
| S&P 500 Index | 100.00 |
| | 102.11 |
| | 118.45 |
| | 156.81 |
| | 178.28 |
| | 180.74 |
| 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
| EEI Index | 100.00 |
| | 119.99 |
| | 122.50 |
| | 138.43 |
| | 178.46 |
| | 171.50 |
| 100.00 |
| | 113.01 |
| | 145.68 |
| | 140.00 |
| | 164.42 |
| | 183.69 |
|
Ameren management cautions that the stock price performance shown in the graph 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) | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Ameren(a): | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 6,098 |
| | $ | 6,053 |
| | $ | 5,838 |
| | $ | 5,781 |
| | $ | 6,148 |
| $ | 6,177 |
| | $ | 6,076 |
| | $ | 6,098 |
| | $ | 6,053 |
| | $ | 5,838 |
|
Operating income(b) | 1,259 |
| | 1,254 |
| | 1,184 |
| | 1,188 |
| | 1,033 |
| 1,458 |
| | 1,381 |
| | 1,259 |
| | 1,254 |
| | 1,184 |
|
Income from continuing operations | 585 |
| | 593 |
| | 518 |
| | 522 |
| | 437 |
| 529 |
| | 659 |
| | 585 |
| | 593 |
| | 518 |
|
Income (loss) from discontinued operations, net of taxes(c)(d) | 51 |
| | (1 | ) | | (223 | ) | | (1,496 | ) | | 89 |
| — |
| | — |
| | 51 |
| | (1 | ) | | (223 | ) |
| Net income (loss) attributable to Ameren common shareholders | 630 |
| | 586 |
| | 289 |
| | (974 | ) | | 519 |
| |
| Net income attributable to Ameren common shareholders | | 523 |
| | 653 |
| | 630 |
| | 586 |
| | 289 |
|
| Common stock dividends | 402 |
| | 390 |
| | 388 |
| | 382 |
| | 375 |
| 431 |
| | 416 |
| | 402 |
| | 390 |
| | 388 |
|
| Continuing operations earnings per share – basic | 2.39 |
| | 2.42 |
| | 2.11 |
| | 2.13 |
| | 1.79 |
| 2.16 |
| | 2.69 |
| | 2.39 |
| | 2.42 |
| | 2.11 |
|
| Continuing operations earnings per share – diluted | 2.38 |
| | 2.40 |
| | 2.10 |
| | 2.13 |
| | 1.79 |
| 2.14 |
| | 2.68 |
| | 2.38 |
| | 2.40 |
| | 2.10 |
|
| Common stock dividends per share | 1.655 |
| | 1.61 |
| | 1.60 |
| | 1.60 |
| | 1.555 |
| 1.778 |
| | 1.715 |
| | 1.655 |
| | 1.61 |
| | 1.60 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
Total assets(d)(e) | $ | 23,640 |
| | $ | 22,289 |
| | $ | 20,907 |
| | $ | 22,022 |
| | $ | 23,667 |
| |
Long-term debt, excluding current maturities(f) | 6,880 |
| | 6,085 |
| | 5,475 |
| | 5,765 |
| | 5,817 |
| |
Total assets(e) | | $ | 25,945 |
| | $ | 24,699 |
| | $ | 23,640 |
| | $ | 22,289 |
| | $ | 20,907 |
|
| Long-term debt, excluding current maturities | | 7,094 |
| | 6,595 |
| | 6,880 |
| | 6,085 |
| | 5,475 |
|
| Total Ameren Corporation shareholders’ equity | 6,946 |
| | 6,713 |
| | 6,544 |
| | 6,616 |
| | 7,919 |
| 7,184 |
| | 7,103 |
| | 6,946 |
| | 6,713 |
| | 6,544 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 3,609 |
| | $ | 3,553 |
| | $ | 3,541 |
| | $ | 3,272 |
| | $ | 3,383 |
| $ | 3,539 |
| | $ | 3,523 |
| | $ | 3,609 |
| | $ | 3,553 |
| | $ | 3,541 |
|
Operating income(b) | 742 |
| | 785 |
| | 803 |
| | 845 |
| | 609 |
| 747 |
| | 745 |
| | 742 |
| | 785 |
| | 803 |
|
Net income available to common shareholder | 352 |
| | 390 |
| | 395 |
| | 416 |
| | 287 |
| 323 |
| | 357 |
| | 352 |
| | 390 |
| | 395 |
|
| Dividends to parent | 575 |
| | 340 |
| | 460 |
| | 400 |
| | 403 |
| 362 |
| | 355 |
| | 575 |
| | 340 |
| | 460 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
Total assets(e) | $ | 13,851 |
| | $ | 13,474 |
| | $ | 12,867 |
| | $ | 12,998 |
| | $ | 12,731 |
| $ | 14,043 |
| | $ | 14,035 |
| | $ | 13,851 |
| | $ | 13,474 |
| | $ | 12,867 |
|
Long-term debt, excluding current maturities(f) | 3,844 |
| | 3,861 |
| | 3,631 |
| | 3,782 |
| | 3,754 |
| 3,577 |
| | 3,563 |
| | 3,844 |
| | 3,861 |
| | 3,631 |
|
| Total shareholders' equity | 4,082 |
| | 4,052 |
| | 3,993 |
| | 4,054 |
| | 4,037 |
| |
| Total shareholders’ equity | | 4,081 |
| | 4,090 |
| | 4,082 |
| | 4,052 |
| | 3,993 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 2,466 |
| | $ | 2,498 |
| | $ | 2,311 |
| | $ | 2,525 |
| | $ | 2,787 |
| $ | 2,528 |
| | $ | 2,490 |
| | $ | 2,466 |
| | $ | 2,498 |
| | $ | 2,311 |
|
| Operating income | 466 |
| | 450 |
| | 415 |
| | 377 |
| | 458 |
| 580 |
| | 544 |
| | 466 |
| | 450 |
| | 415 |
|
| Net income available to common shareholder | 214 |
| | 201 |
| | 160 |
| | 141 |
| | 193 |
| 268 |
| | 252 |
| | 214 |
| | 201 |
| | 160 |
|
| Dividends to parent | — |
| | — |
| | 110 |
| | 189 |
| | 327 |
| — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
Total assets(e) | $ | 8,903 |
| | $ | 8,204 |
| | $ | 7,397 |
| | $ | 7,186 |
| | $ | 7,144 |
| $ | 10,345 |
| | $ | 9,474 |
| | $ | 8,903 |
| | $ | 8,204 |
| | $ | 7,397 |
|
Long-term debt, excluding current maturities(f) | 2,342 |
| | 2,224 |
| | 1,844 |
| | 1,566 |
| | 1,646 |
| |
| Total shareholders' equity | 2,897 |
| | 2,661 |
| | 2,448 |
| | 2,401 |
| | 2,452 |
| |
| Long-term debt, excluding current maturities | | 2,373 |
| | 2,338 |
| | 2,342 |
| | 2,224 |
| | 1,844 |
|
| 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.Also includes regulatory disallowance associated with the Taum Sauk breach of $89 million in 2011. |
| |
| (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 1612 – Divestiture Transactions and Discontinued OperationsIncome Taxes under Part II, Item 8, of this report for additional information. |
| |
| (d) | Includes total assets from discontinued operations of $14 million, $15 million, $165 million, $1,611 million, and $3,721 million at December 31, 2015, 2014, 2013, 2012, and 2011, respectively. |
| |
(e) | Reflects the adoption of the new authoritative accounting guidance for the presentation of debt issuance costs and deferred income taxes. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. |
| |
(f)(e) | Reflects the adoptionIncludes total assets from discontinued operations of the new authoritative accounting guidance for the presentation of debt issuance costs. See Note 1 –Summary of Significant Accounting Policies under Part II, Item 8 of this report for additional information.$165 million at December 31, 2013, and immaterial balances at December 31, 2017, 2016, 2015, and 2014. Total assets from discontinued operations are included in “Other current assets” on Ameren’s balance sheet. |
| |
| ITEM 7. | MANAGEMENT'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 and Ameren Illinois. subsidiaries.Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries.
Below is a summary description of Ameren’s principal subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. Ameren Illinois.also has 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 transmission and distribution business in Missouri.
Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas transmission and distribution businesses in Illinois.
Ameren has various other subsidiaries that conduct activities such as the provision of shared services. Ameren also has a subsidiary, ATXI that 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. projects, and placed the Spoon River project in service in February 2018.
Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission is also pursuing projects to improveprimarily composed of the aggregated electric transmission system reliability withinbusinesses of Ameren Missouri'sIllinois 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' service territories as well as competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO.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 161 – Divestiture Transactions and Discontinued OperationsSummary 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, and therefore their financial statements are not prepared on a consolidated basis. All intercompany transactions have been eliminated.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.
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 2015,2017, Ameren continued to successfully execute its strategy to invest in and to grow its utilities through investment in rate-regulated infrastructure while remaining focused on operational improvement and disciplined cost management. Ameren continues to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks, investing $1.3frameworks. It invested $1.4 billion of capital expenditures in its FERC-regulatedFERC 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 Missouri’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 customer rate increase limitations. The plan also provides for expanding renewable generation, retiring coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs, and adding cost-effective demand response programs. The new renewable energy sources identified in Ameren Missouri’s plan could represent incremental investments of approximately $1 billion through 2020. In connection with the integrated resource plan filing, Ameren Missouri established a goal of reducing CO2 emissions 80% by
2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of its useful life.
In January 2017, Ameren Illinois implemented provisions of the FEJA that improved the constructive regulatory framework of its electric distribution business. The FEJA decoupled electric distribution revenues established in a rate proceeding from actual sales volumes. It provided that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes that are reflected in that year’s rates be collected from, or refunded to, customers within two years. Also, since June 2017, the FEJA has allowed Ameren Illinois to defer the costs of its electric energy-efficiency program as a regulatory asset and earn a return on those investments. The regulatory asset earns a return at the company’s weighted-average cost of capital, with the equity return based on the monthly average 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 savings goals. In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery businesses. Reflecting confidenceservice 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.
In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with Ameren Missouri and an electric cooperative in Ameren’s long-term strategynortheast Missouri to locate almost all of the Mark Twain project on existing line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. In January 2018, the MoPSC granted ATXI a certificate of convenience and outlook,necessity for the Mark Twain project. ATXI plans to begin construction in the second quarter of 2018 and to complete the project by the end of 2019.
In October 2017, Ameren’s board of directors increased the quarterly common stock dividend to 45.75 cents per share, resulting in an annualized equivalent dividend rate in October 2015.
With respect to the FERC-regulated electric transmission businesses, there are currently two complaint cases filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff. In December 2015, an administrative law judge issued an initial decision in the November 2013 complaint case that would lower the allowed base return on common equity to 10.32%. The FERC is expected to issue a final order on the November 2013 complaint case by October 2016. An initial decision from an administrative law judge in the February 2015 complaint case, which will subsequently require FERC approval, is expected to be issued by June 30, 2016. In January 2015, a FERC-approved incentive adder of up to 50 basis points on the allowed base return on common equity for our participation in an RTO became effective. Beginning with its January 2015 effective date, the incentive adder will reduce any refund to customers relating to a reduction of the allowed base return on common equity from the complaint cases.
In December 2015, the ICC issued an order in Ameren Illinois’ annual update filing approving a $106 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2016. Additionally, in December 2015, the ICC issued a rate order that approved an increase in revenues for Ameren Illinois' natural gas delivery service of $45 million. The rate order also approved the VBA for residential and small nonresidential customers beginning in 2016.
Ameren is evaluating the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation investment. In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until such time as legal appeals are concluded. The District of Columbia Circuit Court of Appeals has scheduled hearings for June 2016 on the legality of the rule. A decision by the District of Columbia Circuit Court of Appeals is expected to be issued later this year and additional appeals before the United States Supreme Court are likely. Appeals are
not expected to conclude prior to 2018. Ameren will continue to advocate for responsible energy policies related to the Clean Power Plan while working with key stakeholders to address important issues associated with the Missouri and Illinois state implementation plans should the Clean Power Plan ultimately be upheld.
Ameren Missouri continues to seek legislative solutions to address regulatory lag and to support investment in its utility infrastructure for the benefit of its customers, including through its advocacy for a legislative solution to support Noranda's operations. On January 8, 2016, Ameren Missouri’s largest customer, Noranda, announced that production had been idled at two of its three pot lines at the smelter following an electric supply circuit failure on assets not owned by Ameren Missouri. On February 8, 2016, Noranda filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In the filing, Noranda reaffirmed that the remaining pot line will continue to operate at the smelter until March 2016, at which time operation of the line will be curtailed. Noranda stated it would maintain the flexibility to restart operations at the smelter should conditions allow. In January 2016, Ameren Missouri filed a notice with the MoPSC that would enable Ameren Missouri to file an electric rate case after 60 days. Ameren Missouri expects to file an electric rate case in 2016 and expects the resulting new rates to reflect Noranda’s actual sales volumes which would prospectively eliminate the impact of the current revenue shortfall. Ameren Missouri may seek recovery of lost revenues in a filing with the MoPSC for certain costs incurred but not contemporaneously recovered as a result of Noranda’s reduced operations. Ameren Missouri will continue to monitor Noranda’s sales volumes and to evaluate its regulatory and legislative options that might mitigate adverse financial impacts.
In February 2016, the MoPSC issued an order approving Ameren Missouri’s March 2016 to February 2019 MEEIA plan which included a portfolio of customer energy efficiency programs along with a rider to collect the program costs, the throughput disincentive, and a performance incentive from customers. The plan provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy efficiency goals, including $27 million if 100% of the goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals.$1.83 per share.
Earnings
Net income attributable to Ameren common shareholders from continuing operations was $579$523 million, or $2.38$2.14 per diluted share, for 2015,2017, and $587$653 million, or $2.40$2.68 per diluted share, for 2014. These earnings were2016. Net income was unfavorably affected in 2015,2017, compared with 2014,2016, by increased income tax expense due to a provision recognizednoncash charge to earnings for the revaluation of deferred taxes primarily at Ameren (parent) as a result of Ameren Missouri’s discontinued efforts to licensethe TCJA and build a second nuclear unit at its existing Callaway energy center site as well asthe increase in the Illinois income tax rate. Earnings were also unfavorably affected in 2017, compared with 2016, by decreased electric and natural gas sales volumesdemand, primarily due to warmer winter temperatures. Additionally, increased net financing costs 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 for those businesses not operating under formulaat Ameren Missouri. Net income was favorably affected in 2017, compared with 2016, by an increase in base rates, unfavorably affected earnings. The absence in 2015and lower base level of a recovery of certain previously disallowed
debt premium costs perexpenses at Ameren Missouri, pursuant to the ICC's December 2014MoPSC’s March 2017 electric rate order, also negatively affected earnings. The decrease in Ameren's net income from continuing operations was partially offsetand by increased investments in infrastructure at the Ameren Illinois and ATXI electric transmission serviceElectric Distribution and Ameren Illinois electric delivery service earnings, reflectingTransmission segments, which reflect Ameren’s strategy to allocate significantincremental capital to those businesses. Earnings were positively affected by
After the absenceapplication of jurisdictional regulatory recovery mechanisms, the effect of the revaluation of deferred taxes as a Callaway energy center scheduled refuelingresult of the TCJA was a decrease to Ameren’s and maintenance outage at Ameren Missouri as well as increased Ameren Illinois earnings resulting from a January 2015 ICC order regardingMissouri’s net income of $154 million and $36 million, respectively, while the effect on Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism. Decreased operations and maintenance expenses primarily at Ameren Missouri and at nonregistrant subsidiaries and decreased interest expense at Ameren (parent) also favorably affected earnings.net income was immaterial.
Liquidity
Cash generated by operating activities associated with continuing operations and by issuances of long-term debt were used to fund capital expenditures, repay short-term debt, and pay dividends to common shareholders. At December 31, 2015,2017, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under existing credit agreements,the Credit Agreements of $2.1$1.6 billion.
Capital SpendingExpenditures
In 2015,2017, Ameren madecontinued to make significant investmentsinvestment in its utilities. It expects that trend to continue into the future. From 2016utility businesses by making capital expenditures of $0.8 billion, $0.5 billion, $0.2 billion, and $0.6 billion in Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. For 2018 through 2020, Ameren's2022, Ameren’s cumulative capital spending isexpenditures are projected to range between $10.6from $10.5 billion and $11.5to $11.4 billion. The projected spending by segment includes $4.1up to $4.5 billion, $6.0$2.5 billion, $1.7 billion, and $1.0$2.7 billion for Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and ATXI,Ameren Transmission, respectively. In December 2015, a federal tax law was enacted that authorized the continued use of bonus deprecation 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 investments in utility infrastructure for the benefit of its customers.
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. We are also affecteddemands, as well as by nuclear refueling and other energy center maintenance outages at Ameren Missouri.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, and demand, and many other factors. WeAs described below, we have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas deliverydistribution service businesses, a purchased power cost recovery mechanism for Ameren Illinois'Illinois’ electric deliverydistribution service business, and a FAC for Ameren Missouri'sMissouri’s electric utility business.
Ameren Illinois' electric delivery 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, with recoveries from,as a regulatory asset or refunds to, customers maderegulatory 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 forward-looking 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 delivery 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. While 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.
Earnings Summary
The following table presents a summary of Ameren'sAmeren’s earnings for the years ended December 31, 2015, 2014,2017, 2016, and 2013:2015: |
| | | | | | | | | | | |
| | 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 |
|
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Net income attributable to Ameren common shareholders | $ | 630 |
| | $ | 586 |
| | $ | 289 |
|
| Earnings per common share – diluted | 2.59 |
| | 2.40 |
| | 1.18 |
|
| | | | | | |
| Net income attributable to Ameren common shareholders – continuing operations | 579 |
| | 587 |
| | 512 |
|
| Earnings per common share – diluted – continuing operations | 2.38 |
| | 2.40 |
| | 2.10 |
|
20152017 versus 20142016
Net income attributable to Ameren common shareholders from continuing operations in 20152017 decreased $8$130 million, or $0.02$0.54 per diluted share, from 2014.2016. The decrease was due to a $38 million decreasean increase in net loss of $125 million for activity not reported as part of a segment, primarily at Ameren (parent), and a net income from thedecrease of $34 million at Ameren Missouri, segment,both of which were primarily due to the enactment of the TCJA. The decrease was partially offset by a $13$23 million and a $5 million increase in net income from theAmeren Transmission and Ameren Illinois segment. 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 corporate 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 at Ameren Missouri due 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 pursuant to the MoPSC’s March 2017 electric rate order as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report (32 cents per share);
increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base, partially offset by a lower recognized return on equity (9 cents per share);
increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment as well as a higher recognized return on equity (4 cents per share); and
decreased income tax expense, excluding the effect of corporate income tax rate changes discussed above, primarily at Ameren (parent) resulting from changes in the valuation allowance for charitable contributions, tax benefits related to company-owned life insurance, and tax credits in 2017, partially offset by a lower income tax benefit in 2017 related to share-based compensation compared with 2016 (1 cent per share).
The cents per share information presented above is based on the diluted average shares outstanding in 2016. Pretax amounts have been presented net of income taxes, using Ameren’s 2016 statutory tax rate of 39%.
2016 versus 2015
Net income attributable to Ameren common shareholders from nonregistrant subsidiariescontinuing 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 (parent) in 2015 was $13 million compared with a $4 millionIllinois Electric Distribution, respectively. Additionally, the net loss in 2014, which included net income from ATXI of $31 millionother businesses, primarily Ameren (parent), and $13 million, respectively.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 2014, 2015, 2016 earnings per share from continuing operations were unfavorablyfavorably 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);
decreased electric and natural gas sales volumes primarilyincreased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures in 2015 (estimated at 615 cents per share);
increased net financing costshigher 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 primarily(7 cents per share). This was due, in part, to a reduction in allowance for funds used during construction as multiple significantenergy center maintenance costs, excluding the cost of the Callaway energy center’s scheduled refueling and maintenance outage (discussed below), and reduced electric capital projects were completed in 2014 (6 cents per share);
increased depreciationdistribution maintenance expenditures; and amortization expenses for those businesses not operating under formula rates, primarily resulting from electric capital additions completed in 2014 at Ameren Missouri, which were not reflected in customer rates until May 30, 2015, and amortization of natural gas-related investments at Ameren Illinois (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 Illinois and ATXI electric transmission service and Ameren Illinois electric delivery serviceElectric 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 (20 cents per share). These earnings were reducedpartially offset by the recognition of a liability for a potential refund to customers based on the pending FERC complaint cases regarding the allowed base return on common equity as well as a lower return on equity related to Ameren Illinois electric delivery service investments due toresulting from a reduction in the 30-year United States Treasury bond yields (5(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 absencecost of athe Callaway energy centercenter’s scheduled refueling and maintenance outage in 2015, which last occurred2016. There was no Callaway refueling and maintenance outage in the fourth quarter of 2014, partially offset by preparation costs incurred in 2015 for the 2016 scheduled refueling outage (7 cents per share);
increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri, primarily resulting from additional electric property, plant, and equipment (4 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);
excluding the scheduled refueling and maintenance outage, MEEIA program costs, and expenses with corresponding increases indecreased Ameren Missouri electric revenuesmargins resulting from the April 2015 MoPSC electric rate order, decreasedincreased 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 Missouri primarily because of decreased energy center costs and at nonregistrant subsidiaries (4 cents per share); and
decreased interest expense at Ameren (parent),Illinois Natural Gas, primarily due to the maturity of higher-cost debt in 2014 being replaced with lower-cost debt (3increased repairs and compliance expenditures (2 cents per share).
The cents per share information presented above is based on the diluted average shares outstanding in 2014.
2014 versus 2013
Net2015. Pretax amounts have been presented net of income attributable to Ameren common shareholders from continuing operations in 2014 increased $75 million, or $0.30 per diluted share, from 2013. The increase was due to a $41 million increase in net income from the Ameren Illinois segment and a $39 million decrease in net loss from Ameren (parent) and nonregistrant subsidiaries, which included an increase in ATXI's net income of $6 million. The increase was partially offset by a $5 million decrease in net income from the Ameren Missouri segment.
Compared with 2013, 2014 earnings per share from continuing operations were favorably affected by:
higher natural gas rates at Ameren Illinois pursuant to a December 2013 order (8 cents per share);
decreased interest expense, excluding the effects of the ICC's December 2014 order discussed below, primarily due to the maturity of higher-cost debt replaced with issuances of lower-cost debt (8 cents per share);
the absence in 2014 of a reduction in Ameren Missouri
revenues resulting from a July 2013 MoPSC order that required a refund to customers associated with certain long-term partial requirements sales recognized from October 1, 2009, to May 31, 2011 (7 cents per share);
the ICC's December 2014 order allowing partial recovery of certain previously disallowed debt premium costs that were charged to earnings in 2013 (7 cents per share);
an increase in Ameren Illinois' and ATXI's electric transmission earnings under formula ratemaking due to additional rate base investment, partially offset by the recognition of a liability for a potential refund to customers based on the pending FERC November 2013 complaint case regarding the allowed base return on common equity (6 cents per share);
an increase in Ameren Illinois’ electric delivery service earnings under formula ratemaking pursuant to the IEIMA due to increased rate base investment (estimated at 5 cents per share);
increased net shared benefits realized under the MEEIA at Ameren Missouri (4 cents per share), which were partially offset by lower revenues resulting from reduced demand due to customer energy efficiency programs; and
increased electric and natural gas sales volumes primarily resulting from colder winter temperatures in early 2014 and warmer early summer temperatures (estimated at 1 cent per share).
Compared with 2013, 2014 earnings per share from continuing operations were unfavorably affected by:
increased depreciation and amortization expenses, primarily resulting from electric distribution capital additions at Ameren Missouri (5 cents per share);
an increase in the effectivetaxes, using Ameren’s 2015 statutory tax rate (4 cents per share); and
increased other operations and maintenance expenses for Ameren Missouri and for Ameren Illinois' natural gas business, primarily due to increased labor and litigation costs, offset in part by decreased costs at Ameren (parent), primarily resulting from the substantial elimination of costs previously incurred in support of the divested merchant generation business (3 cents per share)39%.
The cents per share information presented above is based on the diluted average shares outstanding in 2013.
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 aAmeren’s table of income statement components by segment for the years ended December 31, 2015, 2014,2017, 2016, and 2013:2015:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | | | | | | | | | |
| Electric margins | $ | 2,397 |
| | $ | 1,105 |
| | $ | — |
| | $ | 355 |
| | $ | (27 | ) | | $ | 3,830 |
|
| Natural gas margins | 79 |
| | — |
| | 462 |
| | — |
| | (2 | ) | | 539 |
|
| Other revenues | 1 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
|
| Other operations and maintenance | (893 | ) | | (538 | ) | | (215 | ) | | (60 | ) | | 30 |
| | (1,676 | ) |
| Depreciation and amortization | (514 | ) | | (226 | ) | | (55 | ) | | (43 | ) | | (7 | ) | | (845 | ) |
| Taxes other than income taxes | (325 | ) | | (72 | ) | | (58 | ) | | (4 | ) | | (8 | ) | | (467 | ) |
| Other income and (expenses) | 42 |
| | 8 |
| | (1 | ) | | 2 |
| | (9 | ) | | 42 |
|
| Interest charges | (211 | ) | | (72 | ) | | (34 | ) | | (58 | ) | | (7 | ) | | (382 | ) |
| Income taxes | (216 | ) | | (78 | ) | | (39 | ) | | (74 | ) | | 25 |
| | (382 | ) |
| Net income (loss) | 360 |
|
| 127 |
| | 60 |
| | 118 |
| | (6 | ) | | 659 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | $ | 357 |
| | $ | 126 |
| | $ | 59 |
| | $ | 117 |
| | $ | (6 | ) |
| $ | 653 |
|
| 2015 | | | | | | | | | | | |
| Electric margins | $ | 2,481 |
| | $ | 1,074 |
| | $ | — |
| | $ | 259 |
| | $ | (26 | ) | | $ | 3,788 |
|
| Natural gas margins | 80 |
| | — |
| | 425 |
| | — |
| | (2 | ) | | 503 |
|
| Other revenues | 2 |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
|
| Other operations and maintenance | (925 | ) | | (532 | ) | | (219 | ) | | (56 | ) | | 38 |
| | (1,694 | ) |
| Provision for Callaway construction and operating license | (69 | ) | | — |
| | — |
| | — |
| | — |
| | (69 | ) |
| Depreciation and amortization | (492 | ) | | (212 | ) | | (52 | ) | | (33 | ) | | (7 | ) | | (796 | ) |
| Taxes other than income taxes | (335 | ) | | (72 | ) | | (56 | ) | | (2 | ) | | (8 | ) | | (473 | ) |
| Other income and (expenses) | 41 |
| | 8 |
| | (1 | ) | | 2 |
| | (6 | ) | | 44 |
|
| Interest charges | (219 | ) | | (71 | ) | | (35 | ) | | (35 | ) | | 5 |
| | (355 | ) |
| Income taxes | (209 | ) | | (71 | ) | | (24 | ) | | (51 | ) | | (8 | ) | | (363 | ) |
| Income (loss) from continuing operations | 355 |
| | 124 |
| | 38 |
| | 84 |
| | (16 | ) |
| 585 |
|
| Income from discontinued operations, net of taxes | — |
| | — |
| | — |
| | — |
| | 51 |
| | 51 |
|
| Net income | 355 |
| | 124 |
| | 38 |
| | 84 |
| | 35 |
| | 636 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income attributable to Ameren common shareholders | $ | 352 |
| | $ | 123 |
| | $ | 37 |
| | $ | 83 |
| | $ | 35 |
|
| $ | 630 |
|
Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2017, 2016, and 2015: | | | 2015 | Ameren Missouri | | Ameren Illinois | | Other / Intersegment Eliminations | | Total | |
| Electric margins | $ | 2,481 |
| | $ | 1,263 |
| | $ | 44 |
| | $ | 3,788 |
| |
| Natural gas margins | 80 |
| | 425 |
| | (2 | ) | | 503 |
| |
| Other revenues | 2 |
| | — |
| | (2 | ) | | — |
| |
| Other operations and maintenance | (925 | ) | | (797 | ) | | 28 |
| | (1,694 | ) | |
| Provision for Callaway construction and operating license | (69 | ) | | — |
| | — |
| | (69 | ) | |
| Depreciation and amortization | (492 | ) | | (295 | ) | | (9 | ) | | (796 | ) | |
| Taxes other than income taxes | (335 | ) | | (130 | ) | | (8 | ) | | (473 | ) | |
| Other income and (expenses) | 41 |
| | 9 |
| | (6 | ) | | 44 |
| |
| Interest charges | (219 | ) | | (131 | ) | | (5 | ) | | (355 | ) | |
| Income taxes | (209 | ) | | (127 | ) | | (27 | ) | | (363 | ) | |
| Income from continuing operations | 355 |
| | 217 |
| | 13 |
| | 585 |
| |
| Income from discontinued operations, net of taxes | — |
| | — |
| | 51 |
| | 51 |
| |
| Net income | 355 |
| | 217 |
| | 64 |
| | 636 |
| |
| Noncontrolling interests – preferred dividends | (3 | ) | | (3 | ) | | — |
| | (6 | ) | |
| Net income attributable to Ameren common shareholders | $ | 352 |
| | $ | 214 |
| | $ | 64 |
| | $ | 630 |
| |
| 2014 | | | | | | | | |
| Electric margins | $ | 2,436 |
| | $ | 1,179 |
| | $ | 11 |
| | $ | 3,626 |
| |
| Natural gas margins | 82 |
| | 443 |
| | — |
| | 525 |
| |
| Other revenues | 1 |
| | — |
| | (1 | ) | | — |
| |
| Other operations and maintenance | (939 | ) | | (771 | ) | | 26 |
| | (1,684 | ) | |
| Depreciation and amortization | (473 | ) | | (263 | ) | | (9 | ) | | (745 | ) | |
| Taxes other than income taxes | (322 | ) | | (138 | ) | | (8 | ) | | (468 | ) | |
| Other income | 48 |
| | 9 |
| | — |
| | 57 |
| |
| Interest charges | (211 | ) | | (112 | ) | | (18 | ) | | (341 | ) | |
| Income taxes | (229 | ) | | (143 | ) | | (5 | ) | | (377 | ) | |
| Income (loss) from continuing operations | 393 |
| | 204 |
| | (4 | ) | | 593 |
| |
| Loss from discontinued operations, net of taxes | — |
| | — |
| | (1 | ) | | (1 | ) | |
| Net income (loss) | 393 |
| | 204 |
| | (5 | ) | | 592 |
| |
| Noncontrolling interests – preferred dividends | (3 | ) | | (3 | ) | | — |
| | (6 | ) | |
| Net income (loss) attributable to Ameren common shareholders | $ | 390 |
| | $ | 201 |
| | $ | (5 | ) | | $ | 586 |
| |
| 2013 | | | | | | | | |
| 2017 | | Electric Distribution | | Natural Gas | | Transmission | | Total |
| Electric margins | $ | 2,401 |
| | $ | 1,081 |
| | $ | (3 | ) | | $ | 3,479 |
| $ | 1,109 |
| | $ | — |
| | $ | 258 |
| | $ | 1,367 |
|
| Natural gas margins | 83 |
| | 399 |
| | (2 | ) | | 480 |
| — |
| | 479 |
| | — | | 479 |
|
| Other revenues | 1 |
| | 3 |
| | (4 | ) | | — |
| 1 |
| | — |
| | — | | 1 |
|
| Other operations and maintenance | (909 | ) | | (693 | ) | | (9 | ) | | (1,611 | ) | (512 | ) | | (224 | ) | | (53 | ) | | (789 | ) |
| Depreciation and amortization | (454 | ) | | (243 | ) | | (9 | ) | | (706 | ) | (239 | ) | | (59 | ) | | (43 | ) | | (341 | ) |
| Taxes other than income taxes | (319 | ) | | (132 | ) | | (7 | ) | | (458 | ) | (74 | ) | | (60 | ) | | (3 | ) | | (137 | ) |
| Other income and (expenses) | 47 |
| | 1 |
| | (5 | ) | | 43 |
| 3 |
| | (3 | ) | | 1 |
| | 1 |
|
| Interest charges | (210 | ) | | (143 | ) | | (45 | ) | | (398 | ) | (73 | ) | | (36 | ) | | (35 | ) | | (144 | ) |
| Income (taxes) benefit | (242 | ) | | (110 | ) | | 41 |
| | (311 | ) | |
| Income (loss) from continuing operations | 398 |
| | 163 |
| | (43 | ) | | 518 |
| |
| Loss from discontinued operations, net of taxes | — |
| | — |
| | (223 | ) | | (223 | ) | |
| Net income (loss) | 398 |
| | 163 |
| | (266 | ) | | 295 |
| |
| Noncontrolling interests – preferred dividends | (3 | ) | | (3 | ) | | — |
| | (6 | ) | |
| Net income (loss) attributable to Ameren common shareholders | $ | 395 |
| | $ | 160 |
| | $ | (266 | ) | | $ | 289 |
| |
| 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 margins | | $ | 1,105 |
| | $ | — |
| | $ | 232 |
| | $ | 1,337 |
|
| Natural gas margins | | — | | 462 |
| | — | | 462 |
|
| Other operations and maintenance | | (538 | ) | | (215 | ) | | (51 | ) | | (804 | ) |
| Depreciation and amortization | | (226 | ) | | (55 | ) | | (38 | ) | | (319 | ) |
| Taxes other than income taxes | | (72 | ) | | (58 | ) | | (2 | ) | | (132 | ) |
| Other income and (expenses) | | 8 |
| | (1 | ) | | 2 |
| | 9 |
|
| Interest charges | | (72 | ) | | (34 | ) | | (34 | ) | | (140 | ) |
| Income taxes | | (78 | ) | | (39 | ) | | (41 | ) | | (158 | ) |
| Net income | | 127 |
| | 60 |
| | 68 |
| | 255 |
|
| Preferred stock dividends | | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | | $ | 126 |
| | $ | 59 |
| | $ | 67 |
| | $ | 252 |
|
| 2015 | | | | | | | | |
| Electric margins | | $ | 1,074 |
| | $ | — |
| | $ | 189 |
| | $ | 1,263 |
|
| Natural gas margins | | — |
| | 425 |
| | — |
| | 425 |
|
| Other operations and maintenance | | (532 | ) | | (219 | ) | | (46 | ) | | (797 | ) |
| Depreciation and amortization | | (212 | ) | | (52 | ) | | (31 | ) | | (295 | ) |
| Taxes other than income taxes | | (72 | ) | | (56 | ) | | (2 | ) | | (130 | ) |
| Other income and (expenses) | | 8 |
| | (1 | ) | | 2 |
| | 9 |
|
| Interest charges | | (71 | ) | | (35 | ) | | (25 | ) | | (131 | ) |
| Income taxes | | (71 | ) | | (24 | ) | | (32 | ) | | (127 | ) |
| Net income | | 124 |
| | 38 |
| | 55 |
| | 217 |
|
| Preferred stock dividends | | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | | $ | 123 |
| | $ | 37 |
| | $ | 54 |
| | $ | 214 |
|
Margins
The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 20152017 compared with 2014,2016, as well as 20142016 compared with 2013. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less 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.
|
| | | | | | | | | | | | | | | |
| 2015 versus 2014 | Ameren Missouri | | Ameren Illinois | | Other(a) | | Ameren |
| Electric revenue change: | | | | | | | |
Effect of weather (estimate)(b) | $ | (20 | ) | | $ | (10 | ) | | $ | — |
| | $ | (30 | ) |
| Base rates (estimate) | 82 |
| | 34 |
| | — |
| | 116 |
|
| Sales volume (excluding the estimated effect of weather) | (36 | ) | | (1 | ) | | — |
| | (37 | ) |
| Off-system sales and transmission services revenues | 3 |
| | — |
| | — |
| | 3 |
|
| MEEIA net shared benefits | 33 |
| | — |
| | — |
| | 33 |
|
Transmission services revenues(c) | 1 |
| | 29 |
| | 37 |
| | 67 |
|
| Purchased power rider order | — |
| | 15 |
| | — |
| | 15 |
|
| Other | 2 |
| | (7 | ) | | (13 | ) | | (18 | ) |
Cost recovery mechanisms – offset in fuel and purchased power(d) | | | | | | | |
| Power supply costs | — |
| | 81 |
| | — |
| | 81 |
|
| Transmission services recovery mechanism | — |
| | 10 |
| | — |
| | 10 |
|
| Recovery of FAC under-recovery | (5 | ) | | — |
| | — |
| | (5 | ) |
Other cost recovery mechanisms(e) | | | | | | | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | 10 |
| | — |
| | 10 |
|
| Gross receipts tax | 6 |
| | — |
| | — |
| | 6 |
|
| MEEIA program costs | 16 |
| | — |
| | — |
| | 16 |
|
| Total electric revenue change | $ | 82 |
| | $ | 161 |
| | $ | 24 |
| | $ | 267 |
|
| Fuel and purchased power change: | | | | | | | |
| Energy costs | $ | 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 expenses(c) | (7 | ) | | — |
| | — |
| | (7 | ) |
| Other | (1 | ) | | 4 |
| | 9 |
| | 12 |
|
Cost recovery mechanisms – offset in electric revenue(d) | | | | | | | |
| 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 | ) | | $ | (77 | ) | | $ | 9 |
| | $ | (105 | ) |
| Net change in electric margins | $ | 45 |
| | $ | 84 |
| | $ | 33 |
| | $ | 162 |
|
| Natural gas revenue change: | | | | | | | |
Effect of weather (estimate)(b) | $ | (17 | ) | | $ | (72 | ) | | $ | — |
| | $ | (89 | ) |
| Other | 2 |
| | 1 |
| | (2 | ) | | 1 |
|
Cost recovery mechanism – offset in gas purchased for resale(d) | | | | | | | |
| Purchased gas costs | (11 | ) | | (113 | ) | | — |
| | (124 | ) |
Other cost recovery mechanisms(e) | | | | | | | |
| 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 | ) |
| Gas purchased for resale change: | | | | | | | |
Effect of weather (estimate)(b) | $ | 14 |
| | $ | 62 |
| | $ | — |
| | $ | 76 |
|
Cost recovery mechanism – offset in natural gas revenue(d) | | | | | | | |
| Purchased gas costs | 11 |
| | 113 |
| | — |
| | 124 |
|
| Total gas purchased for resale change | $ | 25 |
| | $ | 175 |
| | $ | — |
| | $ | 200 |
|
| Net change in natural gas margins | $ | (2 | ) | | $ | (18 | ) | | $ | (2 | ) | | $ | (22 | ) |
|
| | | | | | | | | | | | | | | |
| 2014 versus 2013 | Ameren Missouri | | Ameren Illinois | | Other(a) | | Ameren |
| Electric revenue change: | | | | | | | |
Effect of weather (estimate)(b) | $ | 8 |
| | $ | (5 | ) | | $ | — |
| | $ | 3 |
|
| Base rates (estimate) | — |
| | 56 |
| | — |
| | 56 |
|
| Sales volume (excluding the estimated effect of weather) | (22 | ) | | 3 |
| | — |
| | (19 | ) |
| Off-system sales and transmission services revenues | (12 | ) | | — |
| | — |
| | (12 | ) |
| FAC prudence review order in 2013 | 25 |
| | — |
| | — |
| | 25 |
|
| MEEIA net shared benefits | 15 |
| | — |
| | — |
| | 15 |
|
| Transmission services revenues | — |
| | 10 |
| | 14 |
| | 24 |
|
| Other | 2 |
| | 6 |
| | (3 | ) | | 5 |
|
Cost recovery mechanisms – offset in fuel and purchased power(d) | | | | | | | |
| Power supply costs | — |
| | (38 | ) | | — |
| | (38 | ) |
| Transmission services recovery mechanism | — |
| | 4 |
| | — |
| | 4 |
|
| Recovery of FAC under-recovery | (14 | ) | | — |
| | — |
| | (14 | ) |
Other cost recovery mechanisms(e) | | | | | | | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | 25 |
| | — |
| | 25 |
|
| MEEIA program costs | 7 |
| | — |
| | — |
| | 7 |
|
| Total electric revenue change | $ | 9 |
| | $ | 61 |
| | $ | 11 |
| | $ | 81 |
|
| Fuel and purchased power change: | | | | | | | |
| Energy costs | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
Effect of weather (estimate)(b) | (5 | ) | | — |
| | — |
| | (5 | ) |
| Other | (1 | ) | | 3 |
| | 3 |
| | 5 |
|
Cost recovery mechanisms – offset in electric revenue(d) | | | | | | | |
| Power supply costs | — |
| | 38 |
| | — |
| | 38 |
|
| Transmission services recovery mechanism | — |
| | (4 | ) | | — |
| | (4 | ) |
| Recovery of FAC under-recovery | 14 |
| | — |
| | — |
| | 14 |
|
| Total fuel and purchased power change | $ | 26 |
| | $ | 37 |
| | $ | 3 |
| | $ | 66 |
|
| Net change in electric margins | $ | 35 |
| | $ | 98 |
| | $ | 14 |
| | $ | 147 |
|
| Natural gas revenue change: | | | | | | | |
Effect of weather (estimate)(b) | $ | 6 |
| | $ | 32 |
| | $ | — |
| | $ | 38 |
|
| Base rates (estimate) | — |
| | 32 |
| | — |
| | 32 |
|
Other
| (2 | ) | | 1 |
| | 2 |
| | 1 |
|
Cost recovery mechanism – offset in gas purchased for resale(d) | | | | | | | |
| Purchased gas costs | (1 | ) | | 57 |
| | — |
| | 56 |
|
Other cost recovery mechanisms(e) | | | | | | | |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | 4 |
| | — |
| | 4 |
|
| Gross receipts tax | — |
| | 3 |
| | — |
| | 3 |
|
| Total natural gas revenue change | $ | 3 |
| | $ | 129 |
| | $ | 2 |
| | $ | 134 |
|
| Gas purchased for resale change: | | | | | | | |
Effect of weather (estimate)(b) | $ | (5 | ) | | $ | (28 | ) | | $ | — |
| | $ | (33 | ) |
Cost recovery mechanism – offset in natural gas revenue(d) | | | | | | | |
| Purchased gas costs | 1 |
| | (57 | ) | | — |
| | (56 | ) |
| Total gas purchased for resale change | $ | (4 | ) | | $ | (85 | ) | | $ | — |
| | $ | (89 | ) |
| Net change in natural gas margins | $ | (1 | ) | | $ | 44 |
| | $ | 2 |
| | $ | 45 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins |
| 2017 versus 2016 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (65 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (70 | ) |
| Base rates (estimate) | 61 |
| | 42 |
| | — |
| | 71 |
| | — |
| | 174 |
|
| Recovery of power restoration efforts provided to other utilities | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | 8 |
|
| Sales volume (excluding the New Madrid Smelter and estimated effect of weather) | (6 | ) | | — |
| | — |
| | — |
| | — |
| | (6 | ) |
| Off-system sales and capacity revenues | 22 |
| | — |
| | — |
| | — |
| | — |
| | 22 |
|
| MEEIA 2013 performance incentive | (28 | ) | | — |
| | — |
| | — |
| | — |
| | (28 | ) |
| Transmission services revenues | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Other | 4 |
| | (1 | ) | | — |
| | — |
| | 5 |
| | 8 |
|
Cost recovery mechanisms – offset in fuel and purchased power(c) | (11 | ) | | 18 |
| | — |
| | — |
| | — |
| | 7 |
|
Other cost recovery mechanisms(d) | 24 |
| | (36 | ) | | — |
| | — |
| | — |
| | (12 | ) |
| Total electric revenue change | $ | 19 |
| | $ | 19 |
| | $ | — |
| | $ | 71 |
| | $ | 5 |
| | $ | 114 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the New Madrid Smelter and estimated effect of weather) | $ | (22 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (22 | ) |
Effect of weather (estimate)(b) | 13 |
| | (1 | ) | | — |
| | — |
| | — |
| | 12 |
|
| Effect of lower net energy costs included in base rates | 39 |
| | — |
| | — |
| | — |
| | — |
| | 39 |
|
| Transmission services charges | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) |
| Other | (10 | ) | | 4 |
| | — |
| | — |
| | (9 | ) | | (15 | ) |
Cost recovery mechanisms – offset in electric revenue(c) | 11 |
| | (18 | ) | | — |
| | — |
| | — |
| | (7 | ) |
| Total fuel and purchased power change | $ | 15 |
| | $ | (15 | ) | | $ | — |
| | $ | — |
| | $ | (9 | ) | | $ | (9 | ) |
| Net change in electric margins | $ | 34 |
| | $ | 4 |
| | $ | — |
| | $ | 71 |
| | $ | (4 | ) | | $ | 105 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
| QIP rider | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Other | — |
| | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
Cost recovery mechanisms – offset in natural gas purchased for resale(c) | 2 |
| | — |
| | (28 | ) | | — |
| | — |
| | (26 | ) |
Other cost recovery mechanisms(d) | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Total natural gas revenue change | $ | (2 | ) | | $ | — |
| | $ | (11 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Cost recovery mechanisms – offset in natural gas revenue(c) | (2 | ) | | — |
| | 28 |
| | — |
| | — |
| | 26 |
|
| Total natural gas purchased for resale change | $ | 2 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 30 |
|
| Net change in natural gas margins | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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) | Primarily includes amounts for ATXIIncludes an increase in transmission margins of $26 million and intercompany eliminations.$43 million in 2017 and 2016, 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 the change in Other of -$6 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) | Ameren MissouriIncludes amounts are subsequent to May 30, 2015, due to the exclusion offor power supply, renewable energy adjustment, zero-emission credits, transmission revenuesservices, and substantially all transmission charges from thepurchased natural gas cost recovery mechanisms, as well as FAC as a result of the April 2015 MoPSC electric rate order. |
| |
(d) | recoveries. Electric and natural gas revenue changes are offset by corresponding changes in Fuel, Purchasedfuel, purchased power, and Gasnatural gas purchased for resale, resulting in no change to electric and natural gas margins. |
| |
(e)(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. |
20152017 versus 20142016
Ameren Corporation
Ameren'sAmeren’s electric margins increased $162$105 million, or 4%3%, in 20152017 compared with 2014. Ameren's2016, primarily because of increased margins at Ameren Transmission and Ameren Missouri. Ameren’s natural gas margins decreased $22increased $17 million, or 4%3%, in 20152017 compared with 2014. These results were primarily driven by Ameren Missouri and2016, because of increased margins at Ameren Illinois results, as discussed below. Ameren's electricNatural Gas.
Ameren Transmission
Ameren Transmission’s margins also reflect the results of operations of ATXI. ATXI’s transmission services revenues increased $37$71 million, or 20%, in 20152017 compared with 2014 because of higher2016. Margins were favorably affected by increased capital investment, as evidenced by an increase in rate base investment andof 23% in 2017 compared with 2016, as well as higher recoverable costs in 2017 compared with 2016 under forward-looking formula ratemaking reducedratemaking. Margins were unfavorably affected by the recognitionabsence in 2017 of a potential refund to customers based on the pending FERC complaint cases regarding thetemporarily higher allowed base return on common equity.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 FERC complaint cases.allowed return on common equity for FERC-regulated transmission rate base.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism that allows it to recover or to refund, through customer rates, 95% of changes in net energy costs greater or less than 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. As of 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, which unfavorably affected margins as discussed below. Ameren Missouri accrues as a regulatory asset net energy costs that exceed the amount set in base rates (FAC under-recovery). 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.
Ameren Missouri'sMissouri’s electric margins increased $45$34 million, or 2%1%, in 20152017 compared with 2014. 2016. Ameren Missouri’s natural gas margins were comparable between years.
The following items had a favorable effect on Ameren Missouri'sMissouri’s electric margins: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.
Higher MEEIA net shared benefitsIncreased 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 increased customer implementation of longer-lived energy efficiency offerings and increased non-residential customer participation,hurricane damage, which increased revenues by $33$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’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’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 Transmission
Ameren Transmission’s margins increased $96 million, or 37%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a 42% increase in rate base used to calculate the revenue requirement, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.
Ameren Missouri
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’s electric 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 included the impact of a provision in the FAC tariff that, under certain circumstances, allowed Ameren Missouri to retain a portion of the revenues from any off-system sales it made as a result of reduced sales to the New Madrid Smelter.
The expiration of MEEIA 2013, 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 Marginstable 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, which decreased margins by $16 million.
The following items had a favorable effect on Ameren Missouri’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 $17$14 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$8248 million) and the change in effect of higher net energy costs included in base rates (-$6534 million) in the Electric and Natural Gas Marginstable 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 programs and other customer energy efficiency measures, and a reduction in Noranda sales volumes. Excluding the estimated effect of weather and reduced sales to Noranda, total retail sales volumes decreased by 1%, which decreased revenues by $25 million. A reduction in Noranda sales volumes decreased revenues by $11 million. Noranda's sales volumes 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 as a result of $24the 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 transmission servicescapacity revenues (+$3153 million) and the change in energy costs (+(excluding the New Madrid Smelter and estimated effect of weather) (-$21145 million) in the Electric and Natural Gas Marginstable above.
Winter temperaturesExcluding 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-efficiency programs. MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes but the throughput disincentive recovery ensured that electric margins were not affected.
Ameren Illinois
Ameren Illinois’ electric margins increased $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
Ameren Illinois Electric Distribution’s margins increased $31 million, or 3%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Electric Distribution’s electric margins:
Revenues increased by $38 million, primarily because 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 2014,2015, as cooling degree-days increased 13%, while heating degree-days decreased 19%5%. The net effect of weather decreasedincreased margins by an estimated $10$7 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-(+$2015 million) and the effect of weather (estimate) on fuel and purchased power (+(-$108 million) in the Electric and Natural Gas Marginstable 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 expenses (-$7 million) and transmission services revenues (+$1 million) in the table above.
Ameren Missouri's natural gas margins were comparable between the years. Ameren Missouri 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 Illinois
Ameren Illinois' electric revenues increased $161 million in 2015 compared with 2014 primarily due to higher power supply costs as a result of increased MISO capacity prices. Ameren Illinois has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its electric customers. These pass-through costs do not affect Ameren Illinois' electric Electric Distribution’s margins as any change in costs is offset by a corresponding change in revenues.
The provisions of the IEIMA and the FERC's electric transmission formula rate framework provide for annual reconciliations of the electric delivery and electric transmission service revenue requirements necessary to reflect the actual costs incurred in a given year with the revenue requirements 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 requirements. In each of those electric jurisdictions, 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 the next 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 refund to customers within the next two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) and transmission services revenues, in the table above, for the electric delivery and electric transmission service revenues, respectively. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.
Ameren Illinois' electric margins increased $84 million, or 7%, in 2015 compared with 2014. The following items had a favorable effect on Ameren Illinois' electric margins:
Electric delivery service revenues that increased by $34 million, primarily because of increased rate base investment and higher recoverable costs under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity for electric delivery service investments due to a reduction in the 30-year United States Treasury bond yields.
Transmission services revenues that increased by $29 million, due to a higher revenue requirement, driven primarily by increased rate base investment and recoverable costs under forward-looking formula ratemaking. These revenues were reducedunfavorably affected by the recognitionabsence in 2016 of a potential refund to customers based on the pending FERC complaint cases regarding the allowed base return on common equity.
A January 2015 ICC order regarding Ameren Illinois'Illinois’ cumulative power usage cost and its purchased power rider mechanism, which caused electric revenues to increaseincreased margins by $15 million in 2015.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $37 million, or 9%, in 2016 compared with 2014.2015. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins:
Ameren Illinois'Higher natural gas revenues decreased $193 millionbase rates in 2015 compared with 2014 due to lower natural gas commodity prices and lower sales volumes due to weather. Ameren Illinois has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased gas costs do not affect Ameren Illinois' natural gas margins, as any change in costs is offset by a corresponding change in revenues.
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%,2016, which decreasedincreased margins by an estimated $10$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 (-(+$7213 million) and the effect of weather (estimate) on gas purchased for resale (+$62 million) in the table above.
2014 versus 2013
Ameren Corporation
Ameren's electric margins increased $147 million, or 4%, in 2014 compared with 2013. Ameren's natural gas margins increased $45 million, or 9%, in 2014 compared with 2013. These results were primarily driven by Ameren Missouri and Ameren Illinois results, as discussed below. Ameren's electric margins also reflect the results of operations of ATXI. ATXI’s transmission services revenues increased $14 million in 2014 compared with 2013 because of higher rate base investment and recoverable costs under forward-looking formula ratemaking. These revenues were reduced by the recognition of a potential refund to customers based on the pending November 2013 FERC complaint case regarding the allowed base return on common equity.
Ameren Missouri
Ameren Missouri's electric margins increased $35 million, or 1%, in 2014 compared with 2013. The following items had a favorable effect on Ameren Missouri's electric margins:
The absence of a charge in 2014 relating to a July 2013 MoPSC FAC prudence review order, which decreased 2013 revenues by $25 million. Ameren Missouri recorded a FAC prudence review charge in 2013 for its estimated obligation to refund to its electric customers the earnings associated with sales recognized by Ameren Missouri from October 1, 2009, to May 31, 2011.
Higher MEEIA net shared benefits driven by increased customer participation, which increased revenue by $15 million. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency-related volume reductions in current and future periods.
Winter temperatures in 2014 were colder compared with 2013, as heating degree-days increased 5%. The effect of weather increased margins by an estimated $3 million. The change in margins due to weather is the sum of the effect of weather on electric revenues (+$8 million) and the effect of weather on fuel and purchased power (-$5 million) in the table above.
Ameren Missouri's electric margins were unfavorably affected by lower sales volumes primarily caused by the MEEIA
programs. Lower sales volumes from energy-efficiency-related volume reductions were offset by MEEIA net shared benefits. Excluding the estimated effect of weather, total retail sales volumes decreased 1%, which decreased revenues by an estimated $22 million, partially offset by a decrease in net energy costs of $6 million. The decrease in net energy costs is the sum of the change in energy costs (+$18 million) and the change in off-system sales and transmission services revenues (-$12 million) in the table above.
Ameren Missouri's natural gas margins were comparable between the years.
Ameren Illinois
Ameren Illinois' electric margins increased $98 million, or 9%, in 2014 compared with 2013. The following items had a favorable effect on Ameren Illinois' electric margins:
Electric delivery service revenues that increased by $56 million, primarily because of increased rate base investment and higher recoverable costs under formula ratemaking pursuant to the IEIMA.
Transmission services revenues that increased by $10 million, largely because of a higher revenue requirement driven primarily by increased rate base investment and recoverable costs under forward-looking formula ratemaking. These revenues were reduced by the recognition of a potential refund to customers based on the pending November 2013 FERC complaint case regarding the allowed base return on common equity.
Excluding the estimated effect of weather, residential retail sales volumes that increased 1%, which increased revenues by $3 million.
Ameren Illinois' electric margins were unfavorably affected by summer temperatures in 2014 that were milder compared with 2013, as cooling degree-days decreased 6%, which decreased margins by an estimated $5 million.
Ameren Illinois' natural gas margins increased $44 million, or 11%, in 2014 compared with 2013. The following items had a favorable effect on Ameren Illinois' natural gas margins:
Higher natural gas delivery service rates effective January 2014, which increased revenues by an estimated $32 million.
Winter temperatures in 2014 were colder compared with 2013 as heating degree-days increased 6%. The effect of weather increased margins by an estimated $4 million. The change in margins due to weather is the sum of the effect of weather on revenues (+$32 million) and the effect of weather on gas purchased for resale (-$2810 million) in the Electric and Natural Gas Marginstable above.
Ameren Illinois Transmission
Ameren Illinois Transmission’s margins increased $43 million, or 23%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a 27% increase in rate base used to calculate the revenue requirement, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.
Other Operations and Maintenance Expenses
20152017 versus 20142016
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 CorporationTransmission
Other operations and maintenance expenses increased $10$3 million in 20152017 compared with 2014. Other operations2016, primarily because of an increase in labor costs due to increased wages and maintenance expenses decreased $14 million at Ameren Missouri and increased $26 million at Ameren Illinois.staffing additions.
Ameren Missouri
Other operations and maintenance expenses were $14$9 million lowerhigher in 20152017 compared with 2014. 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:
AEmployee benefit costs decreased by $21 million, primarily due to a reduction in the base level of $27pension 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 an increase in system operations and labor costs.
Ameren Missouri
Other operations and maintenance expenses were $32 million lower in 2016 compared with 2015. The following items decreased other operations and maintenance expenses between years:
MEEIA customer energy-efficiency program costs decreased by $34 million in 2016, primarily because of the expiration of MEEIA 2013, partially offset by costs incurred for MEEIA 2016.
Energy center maintenance costs, excluding refueling and maintenance
outage costs at the Callaway energy center discussed below, decreased by $18 million, primarily duebecause 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 costs for the 2014 scheduled outage. Costs for the 2014 scheduled outage were $36 million. There was no refueling outage scheduled in 2015; however, $9 million in preparation costs were incurred in 2015 for the 2016 scheduled outage.reduced system repair and vegetation management work.
A decrease of $9 million in employeeEmployee benefit costs decreased by $15 million, primarily due tobecause of a change$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. Electric revenues from customer billings decreased byorder, and lower medical benefit costs, as well as a corresponding amount, with no overall effect on net income.
A reduction of $8$4 million in disposal costs for low-level radioactive nuclear waste.
A decrease of $6 million in energy center maintenance costs, primarily due to reduced major outages at coal-fired energy centers.
A decreasechanges in the market value of $3 million in bad debt expense due to improved customer collections.company-owned life insurance.
The following items increased other operations and maintenance expenses between years:
AmortizationRefueling and maintenance outage costs at the Callaway energy center increased by $26 million, primarily because of $17costs 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 previously deferred solarestimated obligations for pending legal claims.
Solar rebate costs increased by $9 million, as a result of the April 2015 MoPSC electric rate order. Electric revenues from customer billings
Storm-related repair costs increased by a corresponding amount, with no overall effect on net income.$7 million.
An increase of $16 million in MEEIA energy efficiency program costs in 2015 due to program enhancements and increased customer participation. Electric revenues from customer billings increased by a corresponding amount, with no overall effect on net income.
An increase of $3 million due to an unrealized MTM loss in 2015 compared with a gain in 2014, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.
An increase of $2 million in electric distribution maintenance expenditures, primarily related to increased system repair work.
Ameren Illinois
Pursuant to the provisions of the IEIMA's and the FERC's formula rate frameworks, recoverable electric service costs that are not recovered through separate cost recovery mechanisms are included in Ameren Illinois’ revenue requirement reconciliations, which result in corresponding adjustments to electric operating revenues, with no overall effect on net income. These recoverable electric service costs include otherOther operations and maintenance expenses depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.increased $7 million in 2016 compared with 2015, as discussed below.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $26$6 million higher in 20152016 compared with 2014.2015. The following items increased other operations and maintenance expenses between years:
An increaseLabor costs increased by $6 million, primarily because of $8 million in badstaffing 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. These
expenses are included in cost riders that result in additional electric and natural gas revenues, resulting in no overall effect on net income.costs increased by $2 million.
An increase of $7Litigation costs increased by $2 million, in electric delivery maintenance expenditures, primarily related to increased circuit maintenance and system repair work as a result of regulatory compliance requirements.
An increase of $7 millionincreases in labor costs, primarily because of staff additions to meet enhanced reliability standards and customer service goals related to the IEIMA and wage increases.
An increase of $3 million in storm-related repair costs.
An increase of $3 million in employee benefit costs, primarily due to higher pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
An increase of $2 million due to an unrealized MTM loss in 2015 compared with a gain in 2014, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.
2014 versus 2013
Ameren Corporation
Other operations and maintenance expenses increased $73 million in 2014 compared with 2013. Other operations and maintenance expenses increased $30 million at Ameren Missouri and increased $78 million at Ameren Illinois. Partially offsetting the increases at Ameren Missouri and Ameren Illinois were decreased corporate expenses between years of $35 million, primarily due to the substantial elimination of business and administrative costs previously incurred in support of the divested merchant generation business.
Ameren Missouri
Other operations and maintenance expenses were $30 million higher in 2014 compared with 2013. The following items increased other operations and maintenance expenses between years:
An increase of $17 million in labor costs, primarily because of wage increases.
An increase of $14 million in litigation and asbestos claim costs due to severalestimated obligations for pending legal proceedings.
An increase of $8 million in disposal costs for low-level radioactive nuclear waste at the Callaway energy center.
An increase of $7 million in MEEIA energy efficiency program costs in 2014 due to increased customer participation.
A reduction of $3 million in unrealized net MTM gains, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.claims.
The following items decreased other operations and maintenance expenses between years:
A reduction of $13 million in energy center costs, primarily related to coal handling.
A decrease of $7 million in storm-related costs due to fewer major storms in 2014.
A reduction of $2 million in refueling and maintenance costs associated with the scheduled Callaway outages. The 2014 outage costs were $36 million compared with 2013 outage costs of $38 million.
Ameren Illinois
Other operations and maintenance expenses were $78 million higher in 2014 compared with 2013. The following items increased other operations and maintenance expenses between years:
An increase of $29 million in bad debt, customer energy efficiency, and environmental remediation costs.
An increase of $17 million in labor costs, primarily because of staff additions to meet enhanced reliability standards and customer service goals related to the IEIMA and wage increases.
An increase of $13 million in electric delivery maintenance expenditures, primarily related to increased system repair and vegetation management work.
An increase of $8 million in asbestos claim costs.
An increase of $7 million in information technology service expenses, partially related to the IEIMA implementation.
An increase of $6 million in natural gas compliance expenditures, primarily related to pipeline integrity work.
An increase of $4 million in rental expense, primarily related to software from affiliated companies.
A reduction of $2 million in unrealized net MTM gains, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.
Other operations and maintenance expenses decreased between years because of a reduction in employeeEmployee benefit costs of $12decreased 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, and environmental remediation costs decreased by $10 million.
Employee benefit costs decreased by $5 million, primarily because of lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
The following items increased other operations and maintenance expenses between years:
Repairs and compliance expenditures increased by $8 million, primarily 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.
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, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision in 2015 for all of the previously capitalized COL costs. See Note 2 – Rate and Regulatory Matters under Part II, Item 8 of this report for additional information.
Depreciation and Amortization
20152017 versus 2014
Ameren Corporation2016
Depreciation and amortization expenses increased $51 million, $19 million, and $22 million in 20152017 compared with 2014, primarily because of increased expenses2016 at Ameren, Ameren Missouri, and Ameren Illinois, as discussed below.respectively, primarily because of additional property, plant, and equipment across their respective segments.
Ameren Missouri2016 versus 2015
Depreciation and amortization expenses increased $19$49 million, $22 million, and $24 million in 2016 compared with 2015 at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of multiple significant electric projects completed in 2014additional property, plant, and increasedequipment across their respective segments. Additionally, Ameren Missouri’s depreciation rates resulting fromincreased as a result of the April 2015 MoPSC electric rate order.
Ameren Illinois
Depreciation and amortization expenses increased $32 million, primarily because of electric system capital additions and amortization of natural gas-related investments.
2014 versus 2013
Ameren Corporation
Depreciation and amortization expenses increased $39 million in 2014 compared with 2013, primarily because of increased expenses at Ameren Missouri and Ameren Illinois, as discussed below.
Ameren Missouri
Depreciation and amortization expenses increased $19 million, primarily because of electric system capital additions.
Ameren Illinois
Depreciation and amortization expenses increased $20 million, primarily because of electric system capital additions.
Taxes Other Than Income Taxes
20152017 versus 20142016
Ameren Corporation
Taxes other than income taxes increased $5$10 million in 20152017 compared with 2014, primarily because of increased expenses2016, as discussed below. Taxes other than income taxes were comparable at Ameren Missouri, partially offset by decreased expenses at Ameren Illinois, as discussed below.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 $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. The gross receipts tax increase had no effect on net income as electric revenues for gross receipts taxes from customer billings increased by a corresponding amount.
Ameren Illinois
Taxes other than income taxes decreased $8 million, primarily because of decreased gross receipts taxes resulting from lower natural gas sales prices and volumes. Natural gas revenues for gross receipts taxes from customer billings decreased by a corresponding amount, with no overall effect on net income.
2014 versus 2013
Ameren Corporation
Taxes other than income taxes increased $10 million in 2014 compared with 2013, primarily because of increased expenses at Ameren Missouri and Ameren Illinois, as discussed below.
Ameren Missouri
Taxes other than income taxes increased $3 million, primarily because of higher gross receipts taxes resulting from an increase in property taxes resulting from higher tax rates and increased state and local assessments in 2014.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 a $3 million increase indecreased gross receipts taxes as a result of higher natural gas ratesresulting from lower residential and higher sales volumes,commercial electric revenues and because of a $3 million increase indecreased property taxes between years.taxes.
Other Income and Expenses
20152017 versus 20142016
Ameren Corporation
Other income, net of expenses, decreased $13$4 million in 20152017 compared with 2014,2016, primarily because of a $5 million increase in charitable contributionsdue to decreased income at Ameren (parent) due to timing of contributions, and items at Ameren Missouri,Illinois Electric Distribution, as discussed below.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 segments. See Note 6 – Other Income and Expenses under Part II, Item 8, of this report for additional information.
Ameren MissouriIllinois
Other income, net of expenses, decreased $7$8 million, primarily because of lower interest income associated with a decrease in the allowance for equity funds used during construction, as multiple significant electric capital projects were completed in 2014.
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.years at Ameren, Ameren Missouri, Ameren Illinois, and their respective segments.
2014Interest Charges
2017 versus 20132016
Ameren
Interest charges increased $9 million in 2017 compared with 2016, as discussed below.
Ameren CorporationTransmission
Other income, netInterest charges increased $9 million, primarily because of expenses, increased $14an increase in average outstanding debt at Ameren Illinois and ATXI.
Ameren Missouri
Interest charges decreased $4 million, in 2014 compared with 2013, primarily because of a decrease in the average interest rate of debt.
Ameren Illinois
Interest charges increased $4 million, reductionprimarily because of an increase in charitable contributionsaverage outstanding debt, partially offset by a decrease in the average interest rate of debt. Interest charges were comparable between years at each of the Ameren Illinois segments.
2016 versus 2015
Ameren
Interest charges increased $27 million in 2016 compared with 2015, because of an approximately $475 million increase in average outstanding debt and an increase in the average interest rate of debt at Ameren (parent) due. Ameren (parent) issued senior unsecured notes in November 2015 to repay lower-cost short-term debt incurred primarily in connection with the timingfunding of contributions,increasing ATXI investments. An increase in the average interest rate of debt at Ameren Transmission was partially offset by a decrease in the average interest rate 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 (parent)Illinois’ average outstanding debt and an increase in the average interest income from a note receivable with Marketing Company, and items at Ameren Illinois, as discussed below.rate of debt.
Ameren Missouri
Other income, net of expenses, was comparable between years.
Ameren Illinois
Other income, net of expenses, increasedInterest charges decreased $8 million, primarily because of increased income from customer-requested construction, and increased interest income on both the IEIMA 2013 and 2014 revenue requirement reconciliation regulatory assets. Aa decrease in the equity portion of allowance for funds used during construction, primarily due to increased usage of short-term debt to fund capital expenditures, reduced the favorable effect of the above items.
Interest Charges
2015 versus 2014average outstanding debt.
Ameren CorporationIllinois
Interest charges increased $14$9 million, in 2015 compared with 2014.primarily at Ameren Illinois Transmission, as discussed below. Interest charges were comparable between years at Ameren (parent) decreased by $13Illinois Electric Distribution and Ameren Illinois Natural Gas.
Ameren Illinois Transmission
Interest charges increased $9 million, primarily because of a loweran increase in Ameren Illinois’ average interest rate onoutstanding debt in 2015. In May 2014, Ameren (parent) repaid at maturity $425 million of senior unsecured notes, with proceeds from commercial paper issuances. In November 2015, Ameren (parent) issued $700 million of senior unsecured notes, the proceeds of which were used to repay commercial paper borrowings. The interest charges reduction at Ameren (parent) was offset, in part, by increases in interest charges at Ameren Missouri and Ameren Illinois, as discussed below.
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 the issuance of senior secured notes in April 2015.
Ameren Illinois
Interest charges increased $19 million, because of the issuances of senior secured notes in June 2014 and December 2014, the proceeds of which were used to repay commercial paper borrowings, and the absence in 2015 of an $11 million reduction from an ICC electric 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.
2014 versus 2013
Ameren Corporation
Interest charges decreased $57 million in 2014 compared with 2013, primarily because of a $24 million reduction in interest charges at Ameren (parent),construction work in progress as a result of the maturity of $425 million of 8.875% senior unsecured notesmore projects were placed in May 2014, which was replaced with lower cost commercial paper, and a decreaseservice in interest charges associated with uncertain tax positions at Ameren (parent). Additionally, interest charges were lower at Ameren Illinois, as discussed below.2016.
Ameren Missouri
Interest charges were comparable between years. The absence in 2014 of a 2013 reduction to interest charges associated with uncertain tax positions resulted in higher interest charges. See Note 13 – Income Taxes under Part II, Item 8, of this report for information regarding uncertain tax positions. This increase was partially offset by the effect of refinancing activities that resulted in higher-cost debt being replaced with lower-cost debt.
Ameren Illinois
Interest charges decreased $31 million. There was a reduction in interest charges associated with the regulatory liability for the 2012 IEIMA revenue requirement reconciliation as the refund obligation was completed throughout 2014. The 2013 and 2014 IEIMA revenue requirement reconciliations were both regulatory assets, which, as discussed above under Other Income and Expenses, resulted in interest income. Also, the favorable effect of refinancing activities that resulted in higher-cost debt being replaced with lower-cost debt also decreased interest charges. Additionally, the ICC issued an electric rate order in December 2014, which resulted in a partial reversal of a charge recorded in 2013 associated with a December 2013 ICC electric rate order that had disallowed the recovery from customers of certain debt premium costs. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2015, 2014,2017, 2016, and 2013:
| | | | 2015 | 2014 | 2013 | | 2017 | | 2016 | | 2015 | |
| Ameren | 38% | 39% | 38% | Ameren | 52% | (a) | 37% | | 38% | |
| Ameren Missouri | 37% | 37% | 38% | Ameren Missouri | 44% | (b) | 38% | | 37% | |
| Ameren Illinois | 37% | 41% | 40% | Ameren Illinois | 38% | (c) | 38% | | 37% | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Electric Distribution | 38% | (c) | 38% | | 36% | |
| Ameren Illinois Natural Gas | | Ameren Illinois Natural Gas | 38% | (c) | 39% | | 40% | |
| Ameren Illinois Transmission | | Ameren Illinois Transmission | 37% | (c) | 38% | | 37% | |
| Ameren Transmission | | 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.rates for Ameren, Ameren Missouri, and Ameren 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 reduction in the 2016 effective tax rate, as compared with the 2015 effective tax rate, was primarily a result of the recognition of tax benefits associated with share-based compensation resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. This reduction was partially offset by a higher effective tax rate in 2016 as compared with 2015 at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between years at the remaining Ameren segments.
Ameren Illinois
The effective tax rate was comparable between years. The effective tax rate was higher at Ameren Illinois Electric Distribution, primarily because of items detailed below. The effective tax rate was comparable between years at the remaining Ameren Illinois segments.
Ameren Illinois Electric Distribution
The effective tax rate was higher, primarily because of lower tax benefits from certain depreciation differences on property-related items.
Income (Loss) from Discontinued Operations, Net of Taxes
No material activity was recorded associated with discontinued operations in 2017 or 2016. In 2015, based on completion of the IRS audit of Ameren’s 2013 tax year, Ameren recognized a tax benefit of $53 million due to the resolution of an uncertain tax position from discontinued operations. No material activity was recorded associated with discontinued operations in 2014. During the year ended December 31, 2013, the loss from discontinued operations, net of taxes, was primarily related to the impairment loss and related income tax effects associated with the New AER divestiture. See Note 161 – Divestiture Transactions and Discontinued OperationsSummary 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 fromprovided 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 generated fromprovided 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 fromprovided 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, 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 do so over the next five years. Additionally, we may be required to issue incremental debt and/or equity, with available cash on hand, cash generated from operating activities,the long-term intent to maintain strong financial metrics and commercial paper and 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 fromprovided 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, 2015,2017, for Ameren. Ameren'sthe Ameren Companies. The working capital deficit as of December 31, 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, and cash and cash equivalents available, the Ameren Companies had access to $1.8 billion of credit capacity available and $2.1$1.6 billion of liquidity at December 31, 2015.2017.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 20152017, 20142016, and 20132015:
| | | | 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 |
| | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Ameren(a) – continuing operations | $ | 2,021 |
| | $ | 1,557 |
| | $ | 1,636 |
| | $ | (1,951 | ) | | $ | (1,856 | ) | | $ | (1,440 | ) | | $ | 246 |
| | $ | 141 |
| | $ | (149 | ) | $ | 2,104 |
| | $ | 2,124 |
| | $ | 2,035 |
| | $ | (2,205 | ) | | $ | (2,141 | ) | | $ | (1,951 | ) | | $ | 102 |
| | $ | (265 | ) | | $ | 232 |
|
Ameren(a) – discontinued operations | (4 | ) | | (6 | ) | | 57 |
| | (25 | ) | | 139 |
| | (283 | ) | | — |
| | — |
| | — |
| — |
| | (1 | ) | | (4 | ) | | — |
| | — |
| | (25 | ) | | — |
| | — |
| | — |
|
| Ameren Missouri | 1,247 |
| | 950 |
| | 1,143 |
| | (724 | ) | | (837 | ) | | (687 | ) | | (325 | ) | | (113 | ) | | (603 | ) | 1,016 |
| | 1,169 |
| | 1,247 |
| | (685 | ) | | (934 | ) | | (724 | ) | | (331 | ) | | (434 | ) | | (325 | ) |
| Ameren Illinois | 763 |
| | 445 |
| | 651 |
| | (913 | ) | | (828 | ) | | (695 | ) | | 220 |
| | 383 |
| | 45 |
| 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
2015Our 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. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by changes in customer demand due to weather, significantly affect the amount and timing of our cash provided by operating activities. See Part 1, Item 1, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our rate-adjustment mechanisms.
2017 versus 20142016
Ameren Corporation
Ameren’s cash from operating activities associated with continuing operations increased $464decreased $20 million in 2015,2017, compared with 2014.2016. The following items contributed to the increase:decrease:
A $192$48 million increase resultingdecrease 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 electric and natural gas margins, as discussedcustomers in Results of Operations, excluding certain noncash items, as well as2017, was less than the change2014 revenue requirement reconciliation adjustment, which was recovered from customers in customer receivable balances.2016.
A $149$27 million increasedecrease in net energy costs collected from Ameren Missouri customers under the FAC.
A $137$27 million increasedecrease 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' IEIMAIllinois’ transmission revenue requirement reconciliation adjustments, as Ameren Illinois collected $69 millionadjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2015 and refunded $68 million to2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2014.2016.
A $57$14 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 gas prices.reduced withdrawals as a result of milder winter temperatures compared with the prior year.
A $19$13 million decreaseincrease 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 nuclear refuelingadditional reliability, maintenance, 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 2016 spring outage made in 2015.increased natural gas compliance costs.
The following items partially offset the increasedecrease in Ameren'sAmeren’s cash from operating activities associated with continuing operations during 2015, compared to 2014:between years:
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 caused by a change in actuarial assumptions.
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 to 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 caused by a change in actuarial assumptions.
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 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$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 $69$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 taxestax 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 for accelerated depreciation and increased capital expenditures.use of net operating losses.
A $31$23 million increase in natural gas commodity costscash collected from alternative retail electric supplier customers underfor renewable energy credit compliance pursuant to the PGA.
A $26 million decrease in the cost of natural gas held in storage caused primarily by lower gas prices.FEJA.
The following items partially offset the increase in Ameren Illinois’ cash from operating activities during 2015, compared with 2014:between periods:
A net$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 returnscash 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 collateral posted$17 million associated with counterparties, primarily resulting from changesthe November 2013 FERC complaint case, as discussed in the market pricesNote 2 – Rate and Regulatory Matters under Part II, Item 8, of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.this report.
A $12$14 million increase in pension and postretirement benefit plan contributionsthe cost of natural gas held in storage, caused primarily by reduced withdrawals as a change in actuarial assumptions.
A $7$13 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.interest payments, primarily due to an increase in the average outstanding debt.
20142016 versus 20132015
Ameren Corporation
Ameren’s cash from operating activities associated with continuing operations decreased $79increased $89 million in 2014,2016, compared with 2013.2015. The following items contributed to the decrease:increase:
An $89A $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 Missouri’s under-recovered FAC costs. Deferrals and refunds exceeded recoveries in 2014 by $49 million, while recoveries exceeded deferrals in 2013 by $40 million.
Illinois’ IEIMA revenue requirement reconciliation adjustments. The 2014 refunds to Ameren Illinois customers of $67 million as required under the provisions of the IEIMA for the 2012 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
A $38 million increase in cash related to Ameren Illinois’ power procurement cost recovery mechanism.
A $37 million decrease in coal inventory purchases at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.
A $33 million increase in cash related to customer energy-efficiency program recovery mechanisms.
A $19 million increase in cash associated with the recovery of Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.
The following items partially offset the increase in Ameren’s cash from operating activities associated with continuing operations during 2016, compared with no refunds in 2013.2015:
A $65$166 million differencedecrease resulting from the change in expenditures for customer receivable balances.
A $94 million decrease in net energy efficiency programs compared with amountscosts collected from Ameren Missouri and Ameren Illinois customers.
A $50 million increase in coal purchases caused by increased volumes and prices. Ameren Missouri purchased less coal in 2013 due, in part, to delivery disruptions from flooding.
A $42 million difference in purchased power commodity costs incurred compared with amounts collected from Ameren Illinois' customers.
A $39 million increase in rebate payments provided for customer-installed solar generation at Ameren Missouri.
A $38 million decrease in natural gas commodity costs collected from customers under the PGAs, primarily related to Ameren Illinois.
A decrease of $26 million at Ameren Missouri and Ameren Illinois for storm restoration assistance provided to nonaffiliated utilities, primarily due to Hurricane Sandy in 2013.
A $26 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects.
Refunds of $24 million to customers as required by a September 2014 FERC order in Ameren Illinois' wholesale distribution rate case.FAC.
A $23 million increase in interest payments, primarily due to an increase in the valuecost and amount of natural gas heldoutstanding debt of Ameren (parent) and an increase in storagethe average outstanding debt at Ameren Illinois because of increased market prices and timing of injections and withdrawals.Illinois.
A $22$20 million decrease associated with stock-based compensation awards.increase in payments for the refueling and maintenance outage at Ameren Missouri’s Callaway energy center. There was no refueling and maintenance outage in 2015.
A $21$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 $21 million difference in transmission service costs incurred compared with amounts collected from customers, primarily at Ameren Illinois.
A net $19 million decrease in returns of collateral posted with counterparties due to changes at Ameren Missouri and Ameren Illinois discussed below.
A $17$7 million increase in the purchase of receivables from alternative retail electric suppliers compared with amounts collected frompayments to contractors at Ameren Illinois customers.
A $16 million decrease in contributions received by Ameren Illinois from customers for future construction.
An $8 million increase in property tax payments at Ameren Missouri caused by higher assessed property tax valuesadditional reliability, maintenance, and increased property tax rates.
The following items partially offset the decrease in Ameren's cash from operating activities associated with continuing operations during 2014, compared with 2013:
A $240 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.
Income tax refunds of $41 million in 2014, primarily due to federal settlements for the tax years 2007 through 2011, compared with income tax payments in 2013 of $116 million. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for income tax payment (refund) information.
A $76 million decrease in pension and postretirement benefit plan contributions. In addition to the Ameren Missouri and Ameren Illinois amounts discussed below, Ameren's nonregistrant subsidiaries' contributions to the pension and postretirement benefit plans decreased $30 million.
A $29 million decrease in interest payments, primarily due to refinancing activity at Ameren Missouri and Ameren (parent). See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for interest payment information as it relates to continuing and discontinued operations.
A $27 million insurance receipt in 2013 at Ameren Missouri related to the December 2005 breach of the upper reservoir at the Taum Sauk pumped-storage hydroelectric energy center.IEIMA projects.
Ameren’s cash from operating activities associated with discontinued operations decreasedwas immaterial in 2014, compared with 2013. The 2013 activity related to the disposed New AERboth 2016 and the Elgin, Gibson City and Grand Tower energy centers. The 2014 activity related to transaction costs and tax payments associated with the Elgin, Gibson City, and Grand Tower energy centers.2015.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased $193$78 million in 2014,2016, compared with 2013.2015. The following items contributed to the decrease:
A $129$142 million increase in income tax payments paid to Ameren (parent) pursuant to the tax allocation agreement, resulting primarily from fewer deductions for capital expenditures for tax years 2007 through 2013, which caused increased payments in 2014. The increase was partially
offset by a reduction in payments due to the use of net operating loss carryforwards in 2014.
An $89 million decrease in the cash associated with Ameren Missouri’s under-recovered FAC costs. Deferrals and refunds exceeded recoveries in 2014 by $49 million, while recoveries exceeded deferrals in 2013 by $40 million.
A $50 million increase in coal purchases caused by increased volumes and prices. Ameren Missouri purchased less coal in 2013, due, in part, to delivery disruptions from flooding.
A $39 million increase in rebate payments provided for customer-installed solar generation.
A $28 million difference in expenditures for customer energy efficiency programs compared with amounts collected from customers.
An $11 million decrease in natural gas commodity costs collected from customers under the PGA.
A decrease of $10 million for storm restoration assistance provided to nonaffiliated utilities, primarily related to Hurricane Sandy in 2013.
An $8 million increase in property tax payments caused by higher assessed property tax values and increased property tax rates.
The following items partially offset the decrease in Ameren Missouri's cash from operating activities during 2014, compared with 2013:
A $96 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 $27$94 million decrease in net energy costs collected from customers under the FAC.
A $20 million increase in payments for the refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during 2016, compared with 2015:
A $45 million decrease in income tax payments, pursuant to the tax allocation agreement with Ameren (parent), primarily related to higher deductions related to increased capital expenditures in 2016.
A $42 million insurance receipt in 2013 related to the December 2005 breach of the upper reservoir at the Taum Sauk pumped-storage hydroelectric energy center.breach that occurred in December 2005.
A $26$37 million decrease in coal inventory purchases, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.
A $33 million decrease in pension and postretirement benefit plan contributions.
An $11 million increase in cash related to customer energy-efficiency program recovery mechanisms.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased $40 million in 2016, compared with 2015. The following items contributed to the increase:
A $58 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, which was partially offset by the change in customer receivable balances.
A $40 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
A $38 million increase in cash related to the power procurement cost recovery mechanism.
A $22 million decrease in pension and postretirement benefit plan contributions.
A net $10$22 million increase 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.cash related to customer energy-efficiency program recovery mechanisms.
A $9$19 million decreaseincrease in interest payments, primarily duecash 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 refinancing activity.customers in 2015.
Ameren Illinois
The following items partially offset the increase in Ameren Illinois’ cash from operating activities decreased $206during 2016, compared with 2015:
A $121 million decrease resulting from income tax payments of $8 million in 2014,2016, compared with 2013. The following items contributedincome tax refunds of $113 million in 2015, pursuant to the decrease:
The 2014 refunds to customers of $67 million as required under the provisions of the IEIMAtax 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 the 2012 revenue requirement reconciliation adjustment, compared with no refundsincreased capital expenditures in 2013.2015.
A $42 million difference in purchased power commodity costs incurred compared with amounts collected from customers.
A $37 million difference in expenditures for customer energy efficiency programs compared with amounts collected from customers.
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.
A $27 million decrease in natural gas commodity costs collected from customers under the PGA.
A $26 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects.
Refunds to customers of $24 million as required by a September 2014 FERC order in the wholesale distribution rate case.
A $23 million increase in the value of natural gas held in storage because of increased market prices and the timing of injections and withdrawals.
A $21$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 $20 million difference in transmission service costs incurred compared with amounts collected from customers.
A $17$7 million increase in the purchase of receivables from alternative retail electric suppliers compared with amounts collected from customers.payments to contractors for additional reliability, maintenance, and IEIMA projects.
A $16$7 million decreaseincrease in contributions received from customers for future construction.
The absence of $16 million received in 2013 for storm restoration assistance provided to nonaffiliated utilities,interest payments, primarily due to Hurricane Sandy.
The following items partially offset the decrease in Ameren Illinois' cash from operating activities during 2014, compared with 2013:
Electric and natural gas margins, as discussed in Results of Operations excluding certain noncash items, that increased by $126 million.
A $21 millionan increase in income tax refunds from Ameren (parent) pursuant to the tax allocation agreement, resulting primarily from the expected use of net operating loss carryforwardsaverage outstanding debt, including senior secured notes issued in 2014.
A $20 million decrease in pension and postretirement benefit plan contributions.December 2015.
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 expensecost or the legally required minimum contribution. ConsideringBased on Ameren’s assumptions at December 31, 2015,2017, its investment performance in 2015,2017, and its pension funding policy, Ameren expects to make annual contributions of $40less than $1 million to $70$60 million in each of the next five years, with aggregate estimated contributions of $280 million.$120 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 40%35% and 50%55%, respectively. These amounts are estimates. The estimatesThey may
change withbased on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, orand any voluntary contributions. In 2015,2017, Ameren contributed $111$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
20152017 versus 20142016
Ameren'sAmeren’s cash used in investing activities associated with continuing operations increased by $95$64 million during 2015,2017, compared with 2014.2016. Capital expenditures increased $132$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’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 $174$41 million increase forat ATXI primarily related to the Illinois Rivers project, and increased Ameren Missouri and Ameren Illinois capital expenditures partially offset by decreased expenditures at Ameren Missouri.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. 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 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 decreasedincreased by $113$210 million during 2015,2016, compared with 2014.2015. Capital expenditures decreased $125increased $116 million, primarily because several large projects were completedrelated to electric distribution system reliability and energy center projects. Additionally, there was an increase 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.$89 million.
Ameren Illinois’ cash used in investing activities increased by $85$5 million during 2015,2016, compared with 2014,2015, because of increased capital expenditures, primarily for reliability, IEIMA projects, and transmission.
2014 versus 2013
Ameren's cash usedrelated to qualified investments in investing activities associated with continuing operations increased by $416 million during 2014, compared with 2013. Capital expenditures increased $406 million, primarily because of increased transmission expenditures, which included a $150 million increase for ATXI's Illinois Rivers project. In addition, capital expenditures for energy center, reliability and IEIMA projects increased cash used in investing activities and are discussed below.
During 2014, cash provided by investing activities associated with Ameren’s discontinued operations consisted of $152 million received from Rockland Capital fornatural gas infrastructure under the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers in
January 2014, offset by payment of $13 million to IPH for the final working capital adjustment and a portion of certain liabilities associated with the New AER divestiture. In comparison, cash used in investing activities associated with discontinued operations during 2013 was $283 million, primarily because of the requirement to leave $235 million with New AER upon divestiture, pursuant to the transaction agreement with IPH.
Ameren Missouri’s cash used in investing activities increased by $150 million during 2014, compared with 2013. Capital expenditures increased $99 million, primarily for reliability and energy center projects, including the nuclear reactor vessel head replacement project at its Callaway energy center, the electrostatic precipitator upgrades at the Labadie energy center, a new substation in St. Louis, and investment in the O’Fallon energy center, offset by a reduction inQIP rider, storm restoration expenditures. Nuclear fuel expenditures increased by $29 million because of the timing of purchases in 2014 compared with 2013. In addition, cash used in investing activities increased in 2014 because of the absence in 2014 of $24 million in net receipts related to money pool advances received in 2013.
Ameren Illinois' cash used in investing activities increased $133 million during 2014, compared with 2013, because of increased capital expenditures, primarily for transmission, reliability,costs, and IEIMA projects.reliability.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2015, 2014,2017, 2016, and 2013:2015:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
Ameren(a) | $ | 1,917 |
| | $ | 1,785 |
| | $ | 1,379 |
|
| Ameren Missouri | 622 |
| | 747 |
| | 648 |
|
| Ameren Illinois | 918 |
| | 835 |
| | 701 |
|
|
| | | | | | | | | | | |
| | 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.
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 $288$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 $284 million on transmission initiatives 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.
Ameren’s 2013 capital expenditures consisted of expenditures made by its subsidiaries including ATXI, which spent $51 million on the Illinois Rivers project. Ameren Missouri spent $53 million for electrostatic precipitator upgrades at the Labadie energy center, $30 million on storm restoration, and $29 million on the replacement of the nuclear reactor vessel head at its Callaway energy center which was installed during the 2014 refueling and maintenance outage. Ameren Illinois spent $269 million on transmission initiatives, $33 million on IEIMA projects, and $23 million on storm restoration. 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 20162018 through 2020,2022, 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 ATXIAmeren Transmission based, in part, on the more constructive regulatory frameworks within which they operate. These estimates do not include the impacts of the Clean Power Plan. See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for additional information regarding the Clean Power Plan.
| | | | 2016 | | 2017 - 2020 | | Total | 2018 | | 2019-2022 | | Total |
| Ameren Missouri | $ | 835 |
| | $ | 3,095 |
| - | $ | 3,420 |
| | $ | 3,930 |
| - | $ | 4,255 |
| $ | 845 |
| | $ | 3,310 |
| - | $ | 3,660 |
| | $ | 4,155 |
| - | $ | 4,505 |
|
| Ameren Illinois | 905 |
| | 4,820 |
| - | 5,325 |
| | 5,725 |
| - | 6,230 |
| |
| Ameren Illinois Electric Distribution | | 465 |
| | 1,815 |
| - | 2,005 |
| | 2,280 |
| - | 2,470 |
|
| Ameren Illinois Natural Gas | | 330 |
| | 1,220 |
| - | 1,350 |
| | 1,550 |
| - | 1,680 |
|
| Ameren Illinois Transmission | | 470 |
| | 1,765 |
| - | 1,950 |
| | 2,235 |
| - | 2,420 |
|
| ATXI | 410 |
| | 565 |
| - | 625 |
| | 975 |
| - | 1,035 |
| 70 |
| | 215 |
| - | 240 |
| | 285 |
| - | 310 |
|
| Other | 5 |
| | 10 |
| - | 15 |
| | 15 |
| - | 20 |
| 5 |
| | 15 |
| - | 15 |
| | 20 |
| - | 20 |
|
| Ameren | $ | 2,155 |
| | $ | 8,490 |
| - | $ | 9,385 |
| | $ | 10,645 |
| - | $ | 11,540 |
| $ | 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 significant costs in future years 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
2015Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the dividends declared by Ameren’s board of directors, and our long-term debt maturities, among other things.
2017 versus 20142016
Ameren'sAmeren’s financing activities associated with continuing operations provided net cash of $246$102 million in 2015,2017, compared with $141using net cash of $265 million in 2014.2016. During 2015,2017, Ameren (parent) receivedutilized net proceeds from the issuance of $700$1,345 million fromof long-term debtindebtedness to repay $681 million of higher-cost long-term indebtedness, to repay $74 million of net commercial paper issuances, and repaid short-term debt in addition to the activity at Ameren Missouri and Ameren Illinois to fund, maturities of long-term debt and repay short-term debt discussed below. In 2015, the issuances of long-term debt, net of repayments for short-term debt and for long-term debt at maturity, along with cash provided by operating activities were used to fundin part, investing activities and pay dividends.activities. In comparison, during 2014,2016, Ameren utilized net proceeds from the issuance of $646 million of long-term indebtedness
and its registrant subsidiaries issuednet commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and short-term debt to fund, the maturities and redemptions of long-term debt, including the maturity ofin part, investing activities. Additionally, during 2017, Ameren (parent)’s $425made $431 million senior unsecured notes. These financing activities, alongin dividend payments to shareholders, compared with cash provided by operating activities where used to fund investing activities and pay dividends.
$416 million in dividend payments in 2016. No cash from financing activities was used for discontinued operations during 2015.2017.
Ameren Missouri’s cash used in financing activities used net cash of $325decreased by $103 million in 2015,2017, compared with $1132016. 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 2014. During 2015,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 $249 million from a long-term debt issuance, repaid a net $97 million of short-term debt, repaid at maturity $114$507 million of long-term debt,indebtedness and received a $224net commercial paper issuances to repay at maturity $250 million contribution from Ameren (parent).of higher-cost long-term indebtedness. In comparison, during 2014,2016, Ameren Missouri received proceeds of $350 million from a long-term debt issuance and a net $97 million of short-term debt, repaid at maturity $104Illinois issued $291 million of long-term debt,indebtedness and repaid $105 millionnet commercial paper issuances and utilized the proceeds to the money pool. In both years, these financing activities, along with cash provided by operating activities where used to fund investment activities and pay dividends.
Ameren Illinois' financing activities provided net cash of $220 million in 2015, compared with $383 million in 2014. During 2015, Ameren Illinois received proceeds of $248 million from a long-term debt issuance, repaid a net $32repay at maturity $129 million of short-term debt, and repaid $15higher-cost long-term indebtedness. Additionally, in 2017, no dividends were paid to Ameren (parent) compared to $110 million to the money pool. In comparison, during 2014, Ameren Illinois received proceeds of $548 million from two long-term debt issuances and a net $32 million of short-term debt, repaid existing long-term debt of $163 million, and repaid $41 million to the money pool. In both years, these financing activities, along with cash provided by operating activities where used to fund investment activities.paid in 2016.
20142016 versus 20132015
Ameren'sAmeren’s financing activities associated with continuing operations providedused net cash of $141$265 million in 2014,2016, compared with 2013 when Ameren usedproviding net cash of $149 million.$232 million in 2015. During 2014,2016, Ameren utilized net proceeds from the issuance of $646 million of long-term indebtedness and its registrant subsidiaries issuednet commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and short-term debt to fund, the maturities and redemptions of long-term debt, including the maturity of Ameren (parent)’s $425 million senior unsecured notes. In 2014, Ameren used cash from these financing activities, along with cash provided by operating activities to fundin part, investing activities and pay dividends.activities. In comparison, during 2013,2015, Ameren and its registrant subsidiaries issuedutilized net proceeds from the issuance of $1,197 million of long-term and short-term debtindebtedness to fund the maturities and redemptionsrepay $413 million of long-debtnet commercial paper issuances, $120 million of higher-cost long-term indebtedness, and to fund, the $235 million that Ameren was required to leave with New AER upon its divestiture in December 2013, pursuant to the transaction agreement with
IPH. In 2013, Ameren used cash on hand, cash from the issuances of debt, along with cash provided by operating activities to fundpart, investing activities and pay dividends.
activities. No cash from financing activities was used for discontinued operations during 2014.2016.
Ameren Missouri’s cash used in financing activities used net cash of $113increased by $109 million in 2014,2016, compared with $6032015. During 2016, Ameren Missouri utilized net proceeds from the issuance of $149 million of long-term indebtedness, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In comparison, during 2015, Ameren Missouri utilized net proceeds from the issuance of $249 million of long-term indebtedness to repay $120 million of higher-cost long-term indebtedness and $97 million of net commercial paper issuances. Additionally, during 2016, Ameren Missouri paid $355 million in 2013. During 2014,dividends to Ameren (parent), compared with $575 million dividends paid in the year-ago period. Also, in 2016, Ameren Missouri received proceeds of $350$44 million as a capital contribution from a long-term debt issuance and a net $97Ameren (parent) compared to $224 million from short-term debt, repaid at maturity $104received in 2015.
Ameren Illinois’ cash provided by financing activities decreased by $176 million in 2016, compared with 2015. During 2016, Ameren Illinois issued $291 million of long-term debt, repaid $105indebtedness and net commercial paper issuances and utilized the proceeds to repay at maturity $129 million to the money pool.of higher-cost long-term indebtedness. In comparison, during 2013,2015, Ameren Missouri repaid $244Illinois utilized proceeds from the issuance of $248 million of long-term debt,indebtedness to repay $32 million of net commercial paper issuances and received $105 million from the money pool. In both years, including cash on hand during 2013, these financing activities, along with cash provided by operating activities were used to fund, investment activities and pay dividends.
in part, investing activities. Additionally, in 2016 Ameren Illinois' financing activities provided net cash of $383Illinois paid $110 million in 2014,dividends to Ameren (parent) compared with $45 millionto no dividends paid in 2013. During 2014, Ameren Illinois received proceeds of $548 million from two long-term debt issuances and a net $32 million from short-term debt, repaid existing long-term debt of $163 million, and repaid $41 million to the money pool. In comparison, during 2013, Ameren Illinois received proceeds of $278 million from a long-term debt issuance, repaid at maturity $150 million of long-term debt, and paid dividends. In both years, these financing activities, along with cash provided by operating activities were used to fund investment activities.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 committed bank credit agreements,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, 20152017:
| | | | | Available at December 31, 2015 | | 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 | | 176 |
| | 224 |
|
| Less: Ameren Missouri commercial paper outstanding | | | 39 |
|
Missouri Credit Agreement – credit available | | 824 |
| | 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 | | 125 |
| | 159 |
|
| Less: Ameren Illinois commercial paper outstanding | | | 62 |
|
| Less: Letters of credit | | 13 |
| | 1 |
|
Illinois Credit Agreement – credit available | | 962 |
| | 878 |
|
| Total Credit Available | | $ | 1,786 |
| | $ | 1,615 |
|
| Cash and cash equivalents | | 292 |
| | 10 |
|
| Total Liquidity | | $ | 2,078 |
| | $ | 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. |
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 currently scheduled to mature in December 2019, but the maturity date may be extended once or twice for 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’s,Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. EitherBoth 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. During 2015, borrowingsIssuances 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. As such, commercialCommercial paper issuances were thus preferred to credit facility borrowings as a preferred source of third-party short-term debt relative to credit facility borrowings.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 |
|
Subject to applicable regulatory short-term borrowing authorizations, these credit arrangements are also available to Ameren's other subsidiaries through direct short-term borrowings from Ameren including, but not limited to, Ameren Services, throughhas a money pool agreement. Ameren has money pool agreementsagreement 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 borrowwill access funds from the utility money pool, when funds are available before utilizing the Credit Agreements, andor the commercial paper programs becausedepending on which option has the utility money poollowest interest rates are typically lower.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 arrangements.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 January 2016, Ameren Missouri requested an extension of its existing FERC authorization to issue up to $1 billion of short-term debt securities through March 2018. Ameren Missouri expects FERC approval of that authorization in March 2016. In September 2014,June 2017, the FERC issued an order authorizing Ameren Illinois to issue up to $1 billion of short-term debt securities through September 15, 2016. In July 2015, the FERC
issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 14, 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 theour issuances (net of issuance premiums or discounts), redemptions, repurchases, and maturities of long-term debt for the years ended December 31, 20152017, 20142016, and 20132015 for the Ameren Companies.. The Ameren Companies did not issue any common stock or redeem or repurchase any preferred stock during the years ended 20152017, 20142016, and 20132015. In 20152017, 2016, and 2014,2015, Ameren Missouri received cash capital contributions as a result of $224 millionthe tax allocation agreement from Ameren (parent). In 2017 and $215 million, respectively,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 | | 2015 | | 2014 | | 2013 |
| Issuances | | | | | | | |
| Ameren (parent) | | | | | | | |
| 2.70% Senior unsecured notes due 2020 | November | | $ | 350 |
| | $ | — |
| | $ | — |
|
| 3.65% Senior unsecured notes due 2026 | November | | 350 |
| | — |
| | — |
|
| Ameren Missouri: | | | | | | | |
| 3.50% Senior secured notes due 2024 | April | | — |
| | 350 |
| | — |
|
| 3.65% Senior secured notes due 2045 | April | | 249 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | |
| 4.80% Senior secured notes due 2043 | December | | — |
| | — |
| | 278 |
|
| 4.30% Senior secured notes due 2044 | June | | — |
| | 248 |
| | — |
|
| 3.25% Senior secured notes due 2025 | December | | — |
| | 300 |
| | — |
|
| 4.15% Senior secured notes due 2046 | December | | 248 |
| | — |
| | — |
|
| Total long-term debt issuances | | | $ | 1,197 |
| | $ | 898 |
| | $ | 278 |
|
| Redemptions, Repurchases, and Maturities | | | | | | | |
| Ameren (Parent): | | | | | | | |
| 8.875% Senior unsecured notes due 2014 | May | | $ | — |
| | $ | 425 |
| | $ | — |
|
| Ameren Missouri: | | | | | | | |
| City of Bowling Green capital lease (Peno Creek CT) | December | | 6 |
| | 5 |
| | 5 |
|
| 1993 5.45% Series pollution control revenue bonds due 2028 | October | | — |
| | — |
| | 44 |
|
| 4.65% Senior secured notes due 2013 | October | | — |
| | — |
| | 200 |
|
| 5.50% Senior secured notes due 2014 | May | | — |
| | 104 |
| | — |
|
| 4.75% Senior secured notes due 2015 | April | | 114 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | |
| 8.875% Senior secured notes due 2013 | December | | — |
| | — |
| | 150 |
|
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 |
| | — |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 120 |
| | $ | 697 |
| | $ | 399 |
|
|
| | | | | | | | | | | | | |
| | Month Issued, Redeemed, Repurchased, or Matured | | 2017 | | 2016 | | 2015 |
| Issuances of Long-term Debt | | | | | | | |
| Ameren (parent) | | | | | | | |
| 2.70% Senior unsecured notes due 2020 | November | | $ | — |
| | $ | — |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | November | | — |
| | — |
| | 350 |
|
| Ameren Missouri: | | | | | | | |
| 3.65% Senior secured notes due 2045 | April | | — |
| | — |
| | 249 |
|
| 3.65% Senior secured notes due 2045 | June | | — |
| | 149 |
| | — |
|
| 2.95% Senior secured notes due 2027 | June | | 399 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | |
| 3.70% First mortgage bonds due 2047 | November | | 496 |
| | — |
| | — |
|
| 4.15% Senior secured notes due 2046 | December | | — |
| | 240 |
| | 248 |
|
| ATXI: | | | | | | | |
| 3.43% Senior notes due 2050 | June | | 150 |
| | — |
| | — |
|
| 3.43% Senior notes due 2050 | August | | 300 |
| | — |
| | — |
|
| Total long-term debt issuances | | | $ | 1,345 |
| | $ | 389 |
| | $ | 1,197 |
|
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | | | |
| Ameren Missouri: | | | | | | | |
| 5.40% Senior secured notes due 2016 | February | | — |
| | 260 |
| | — |
|
| 4.75% Senior secured notes due 2015 | April | | — |
| | — |
| | 114 |
|
| 6.40% Senior secured notes due 2017 | June | | 425 |
| | — |
| — | — |
|
| City of Bowling Green capital lease (Peno Creek CT) | December | | 6 |
| | 6 |
| | 6 |
|
| Ameren Illinois: | | | | | | | |
| 6.20% Senior secured notes due 2016 | June | | — |
| | 54 |
| | — |
|
| 6.25% Senior secured notes due 2016 | June | | — |
| | 75 |
| | — |
|
| 6.125% Senior secured notes due 2017 | November | | 250 |
| | — |
| | — |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 681 |
| | $ | 395 |
| | $ | 120 |
|
(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 February 2016,November 2017, Ameren Missouri's 5.40%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 and were repaid using available cash and commercial paper borrowings.in November 2017.
In June 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. 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, 2015,2017, 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 generated fromprovided 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 $402$431 million,, or $1.655$1.778 per share, in 2015, $3902017, $416 million,, or $1.61$1.715 per share, in 2014,2016, and $388$402 million,, or $1.60$1.655 per share, in 2013.2015.
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 12, 2016,9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 42.545.75 cents per share, payable on March 31, 2016,29, 2018, to shareholders of record on March 9, 2016.14, 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, 2015,2017, the amount of restricted net assets of wholly ownedAmeren’s subsidiaries of Ameren that may not be distributed to Ameren in the form of a loan or dividend was $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:
| | | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Ameren | | $ | 431 |
| | $ | 416 |
| | $ | 402 |
|
| Ameren Missouri | $ | 575 |
| | $ | 340 |
| (a) | $ | 460 |
| 362 |
| | 355 |
| | 575 |
|
| Ameren Illinois | — |
| | — |
| | 110 |
| — |
| | 110 |
| | — |
|
| Ameren | 402 |
| | 390 |
| | 388 |
| |
| |
(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, 20152017. 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) | $ | 395 |
| | $ | 1,521 |
| | $ | 1,023 |
| | $ | 4,392 |
| | $ | 7,331 |
| $ | 841 |
| | $ | 1,023 |
| | $ | 514 |
| | $ | 5,617 |
| | $ | 7,995 |
|
Interest payments(c) | 362 |
| | 626 |
| | 435 |
| | 2,771 |
| | 4,194 |
| 464 |
| | 855 |
| | 814 |
| | 5,018 |
| | 7,151 |
|
Operating leases(d) | 14 |
| | 25 |
| | 23 |
| | 30 |
| | 92 |
| |
Other obligations(e) | 1,323 |
| | 1,676 |
| | 557 |
| | 1,128 |
| | 4,684 |
| |
| Operating leases | | 10 |
| | 17 |
| | 12 |
| | 14 |
| | 53 |
|
Other obligations(d) | | 981 |
| | 964 |
| | 206 |
| | 254 |
| | 2,405 |
|
| Total cash contractual obligations | $ | 2,094 |
| | $ | 3,848 |
| | $ | 2,038 |
| | $ | 8,321 |
| | $ | 16,301 |
| $ | 2,296 |
| | $ | 2,859 |
| | $ | 1,546 |
| | $ | 10,903 |
| | $ | 17,604 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 266 |
| | $ | 814 |
| | $ | 673 |
| | $ | 2,382 |
| | $ | 4,135 |
| $ | 384 |
| | $ | 673 |
| | $ | 64 |
| | $ | 2,867 |
| | $ | 3,988 |
|
Interest payments(c) | 211 |
| | 367 |
| | 259 |
| | 1,687 |
| | 2,524 |
| 331 |
| | 592 |
| | 575 |
| | 3,208 |
| | 4,706 |
|
Operating leases(d) | 12 |
| | 22 |
| | 21 |
| | 29 |
| | 84 |
| |
Other obligations(e) | 833 |
| | 1,178 |
| | 325 |
| | 469 |
| | 2,805 |
| |
| Operating leases | | 8 |
| | 15 |
| | 12 |
| | 14 |
| | 49 |
|
Other obligations(d) | | 628 |
| | 654 |
| | 163 |
| | 194 |
| | 1,639 |
|
| Total cash contractual obligations | $ | 1,322 |
| | $ | 2,381 |
| | $ | 1,278 |
| | $ | 4,567 |
| | $ | 9,548 |
| $ | 1,351 |
| | $ | 1,934 |
| | $ | 814 |
| | $ | 6,283 |
| | $ | 10,382 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
Long-term debt(b) | $ | 129 |
| | $ | 707 |
| | $ | — |
| | $ | 1,660 |
| | $ | 2,496 |
| $ | 457 |
| | $ | — |
| | $ | 400 |
| | $ | 2,000 |
| | $ | 2,857 |
|
Interest payments(c) | 129 |
| | 215 |
| | 132 |
| | 1,019 |
| | 1,495 |
| 106 |
| | 188 |
| | 185 |
| | 1,584 |
| | 2,063 |
|
Operating leases(d) | 1 |
| | 2 |
| | 2 |
| | 1 |
| | 6 |
| |
Other obligations(e) | 452 |
| | 479 |
| | 232 |
| | 659 |
| | 1,822 |
| |
| Operating leases | | 1 |
| | — |
| | — |
| | 1 |
| | 2 |
|
Other obligations(d) | | 352 |
| | 310 |
| | 43 |
| | 40 |
| | 745 |
|
| Total cash contractual obligations | $ | 711 |
| | $ | 1,403 |
| | $ | 366 |
| | $ | 3,339 |
| | $ | 5,819 |
| $ | 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 $56$60 million, $2527 million, and $25$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, 20152017. |
| |
| (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 discussion of items included herein.
|
| |
(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, 2015,2017, Ameren, Ameren Missouri, and Ameren Illinois had no unrecognized tax benefits (detriments) for uncertain tax positions.
Off-Balance-Sheet Arrangements
At December 31, 2015,2017, 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 |
The cost of borrowing under our credit facilities can also fluctuate depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
Collateral Postings
Any adverse change inweakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial at Ameren, Ameren Missouri, and Ameren Illinois at December 31, 2015. Sub-investment-grade2017. A sub-investment-grade issuer or senior unsecured debt rating (lower than(whether below “BBB-” from S&P or below “Baa3”) from Moody’s) at December 31, 2015,2017, 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 $143$82 million, $72$44 million, and $71$38 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2015,2017, if market prices were 15% higher or lower than December 31, 20152017, 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 would onlycould be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade obligations.
OUTLOOK
We seek to earn competitive returns on investments in our businesses. We are seekingseek to improve our regulatory frameworks and cost recovery mechanisms and are simultaneously pursuing constructive regulatory outcomes within existing frameworks.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. Consequently, we are focusedregulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity. We intend to allocateequity and allocating capital resources to our business opportunities that we expect towill offer the most attractive risk-adjusted return potential.
As part of Ameren’s strategic plan, we pursue projects to meet our customer energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories. Ameren also evaluates competitive electric transmission investment opportunities as they arise. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition to a more diverse energy generation portfolio.
Below are some key trends, events, and uncertainties that 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 20162018 and beyond.
Operations
Our strategy for earning competitive returns on our investments involves meeting customer energy needs in an efficient fashion, working to enhance regulatory frameworks, making timely and well-supported rate case filings, and aligning overall spending with those rate case outcomes, economic conditions, and return opportunities.
Ameren continues to pursue its plans to invest in FERC-regulated electric transmission. MISOATXI has approved three electric transmissionMISO-approved multi-value projects, to be developed by ATXI. The first project,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, was placed in service in February 2018. The Mark Twain project, located in northeast Missouri and connecting the Illinois Rivers project to Iowa, is expected to be completed by the end of 2019. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the Mark Twain project in northeast Missouri areand its approval process and the other two MISO-approved projects to be constructed by ATXI. These two projects are expected to be completed in 2018. The Illinois Rivers and the Spoon River projects have received allproject. As of the necessary commission approvals to authorize their construction while ATXI is still seeking approval from the MoPSC for the Mark Twain project.The totalDecember 31, 2017, ATXI’s expected remaining investment in all three projects is expectedapproximately $300 million, with the total investment to be more than $1.0 billion from 2016 through 2019. This total includes over $60 million of investment by Ameren Illinois to construct connections to its existing transmission system.$1.6 billion. In addition, to its investment in the MISO-approved projects, Ameren Illinois expects to invest $1.9$2.3 billion in electric transmission assets from 20162018 through 20202022 to address load growthreplace aging infrastructure and reliability requirements.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. With the rates that became effectiveBased on January 1, 2016,expected rate base growth and the currently allowed 12.38% return on equity, the 2016 revenue requirement for Ameren Illinois’ electric transmission business would be $241 million, which represents a $42 million increase over the 2015 revenue requirement due to rate base growth. These rates reflect a capital structure composed of 51.9% common equity and a projected rate base of $1.2 billion. With the rates that became effective on January 1, 2016, and the currently allowed 12.38% return on equity, the 2016 revenue requirement for ATXI’s electric transmission business would be $140 million, which represents a $60 million increase over the 2015 revenue requirement due to rate base growth, primarily as a result of the Illinois Rivers project. These rates reflect a capital structure composed of 56.1% common equity and a projected rate base of $0.9 billion.
The 12.38%10.82% return on common equity, is the subject2018 revenue requirements for Ameren Illinois’ and ATXI’s electric transmission businesses are $270 million and $174 million, respectively. These revenue requirements represent an increase in Ameren Illinois' and ATXI's revenue requirements of two FERC complaint proceedings,$11 million and $4 million, respectively, primarily because of the November 2013 complaint case andrate base growth described above, partially offset by a decrease due to the February 2015 complaint case, that challengelower federal statutory corporate income tax rates enacted under the allowed baseTCJA.
The return on common equity for MISO transmission owners. In December 2015,owners, including Ameren Illinois and ATXI, was the subject of a FERC administrative law judge issued an initial decision in the November 2013 complaint case that would lowerfiled in February 2015 which challenged the allowed base return on common equity. Ameren Illinois and ATXI currently use the FERC authorized total allowed return on common equity of 10.82% in customer rates. A final FERC order would establish the allowed return on common equity to 10.32%.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 the effective date of such order, replacing the current 10.82% total return on common equity. The FERC is expectedtiming and amount of any adjustment to issuethe total allowed return on common equity that may be ordered as a final order onresult of the November 2013 complaint case by October 2016. An initial decision from an administrative law judge in the February 2015 complaint case is expected to be issued by June 30, 2016, which will subsequently require FERC approval.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 $6$8 million and $3$4 million, respectively, based on each company’s 20162018 projected rate base. AmerenSee Note 2 – Rate and Ameren Illinois recorded current regulatory liabilities on their respective balance sheets asRegulatory Matters under Part II, Item 8, of December 31, 2015, representing their estimate of the potential refunds from the November 2013 refund effective date through December 2015.this report for information regarding FERC complaint cases.
In January, 2015, a FERC-approved incentive adder of up to 50 basis points on the allowed base return on common
equity for our participation in an RTO became effective. Upon the issuance of the final order addressing the November 2013 complaint case, beginning with its January 2015 effective date, the incentive adder will reduce any refund to customers relating to a reduction of the base return on common equity.
In April 2015,March 2017, the MoPSC issued an order approving a $122unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenuesrevenue requirement for electric service, including $109 million related to the increase in net energy costs above those included in base rates previously authorized by the MoPSC. The revenue increase was based on a 9.53% return on common equity, a capital structure composed of 51.8% common equity, and a rate base of $7.0 billion to reflect investments through December 31, 2014. Rate changes consistentcompared with the order became effective on May 30, 2015. Ameren Missouri’sprior revenue requirement prior to May 30, 2015, was based on a 9.8% return on common equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion. Accordingly, the level of earnings reflectedestablished in the revenue requirement in effect after May 30, 2015, is lower than the level of earnings reflected in the previously effective revenue requirement. The order approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude all transmission revenues and substantially all transmission charges. The order did not approve the continued use of regulatory tracking mechanisms for storm costs or for vegetation management and infrastructure inspection costs. These changes to Ameren Missouri’s recovery mechanisms are expected to contribute to regulatory lag. For example, the April 2015 MoPSC electric rate order included $29 million of transmission charges in base rates that were previously included in the FAC. Ameren Missouri expects transmission charges to increase to $53 million in 2016, with further cost increases expected in the foreseeable future. However, transmission revenues included in base rates in the April 2015 MoPSC electric rate order totaled $34 million and are expected to remain relatively constant in 2016 and into the near future.
Ameren Missouri supplies electricity to Noranda’s aluminum smelter located in southeast Missouri. In itsMoPSC’s April 2015 electric rate order,order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017. Excluding cost reductions associated with reduced sales volumes, the MoPSC approved a rate design thatbase level of net energy costs decreased by $54 million from the base level established $78 million in annual revenues, net of fuel and purchased power costs, as Noranda’s portion of Ameren Missouri’s revenue requirement. The portion of Ameren Missouri’s annual revenue requirement reflected in Noranda’sthe MoPSC’s April 2015 electric rate is based onorder. Changes in amortizations and the smelter using approximately 4.2base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million megawatthours annually, which is almost 100% of its operating capacity. In January 2016, Noranda announced that production had been idled at two of its three pot lines following an electric supply circuit failure and that from the third pot line, which was not directly affected bybase levels established in the circuit failure, will be curtailed on or before March 12, 2016, unless Noranda "is able to secure a substantially more sustainable power rate." On February 8, 2016, Noranda filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In the filing, Noranda reaffirmed that the
remaining pot line will continue to operate at the smelter until March 2016, at which time operation of the line will be curtailed. Noranda stated it would maintain the flexibility to restart operations at the smelter should conditions allow. As a result of these events in 2016, actual sales volumes to Noranda will be significantly below the sales volumes reflected in rates and therefore, Ameren Missouri will not fully recover its revenue requirement until rates are adjusted by the MoPSC in a futureMoPSC’s April 2015 electric rate case to reflect Noranda’s actual sales volumes. Ameren Missouri estimates a $32 million reduction in 2016 earnings, compared to 2015, relating toorder.
In December 2017, the significantly lower expected electric sales volumes to Noranda after consideration of the FAC provision that allows Ameren Missouri to retain a portion of its off-system sales. In January 2016, Ameren Missouri filed a notice with the MoPSC that would enable Ameren Missouri to file an electric rate case after 60 days. Ameren Missouri expects to file an electric rate case in 2016 and expects the resulting new rates to reflect Noranda's actual sales volumes which would prospectively eliminate the impact of the current revenue shortfall. Rate case proceedings take place over a period of up to 11 months from the date of filing. Ameren Missouri will continue to monitor Noranda’s sales volumes and to evaluate its regulatory and legislative options that might mitigate adverse financial impacts.
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 plan approved in August 2012. Additionally, the plan established a performance incentive that would provide Ameren Missouri an opportunity to earn additional revenues based on its achievement of certain customer energy efficiency goals, including $19 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 June 2015, the MoPSC staff filed a complaint case with the MoPSC regarding the method and inputs used in calculating the performance incentive for 2014 and 2015. In November 2015, the MoPSCICC issued an order that adopted the MoPSC staff’s method and inputs used in calculating the performance incentive for 2014 and 2015. Ameren Missouri has filed an appeal of the order with the Missouri Court of Appeals, Western District. If the Missouri Court of Appeals upholds the MoPSC order, the performance incentive awarded from the 2014 and 2015 MEEIA programs will be significantly less than the performance incentive calculated using Ameren Missouri’s interpretation. Ameren Missouri has not recorded revenues associated with the performance incentive for any of the MEEIA program years. Ameren Missouri believes it will ultimately be found to have exceeded 100% of the customer energy efficiency goals, and it therefore expects to recognize revenues of at least $19 million in 2016.
Net shared benefits compensated Ameren Missouri for the current year and longer-term financial impacts of customer energy efficiency programs in each year of the program from 2013 through 2015. The March 2016 through February 2019 MEEIA plan is designed differently. The throughput disincentive included in the March 2016 through February
2019 MEEIA plan is designed to make Ameren Missouri earnings neutral each year for its customer energy efficiency investments, including the lost sales volumeIllinois’ annual update filing that occur in that year, and does not compensate for the longer-term financial impacts of customer energy efficiency programs until those sales volumes are lost in a future year. The unfavorable effects of sales volume reductions in 2016 from the 2013 through 2015 energy efficiency programs were previously recognized during those years as net shared benefits and, therefore, any such lost sales volumes will negatively impact 2016 earnings.
In February 2016, the MoPSC issued an order approving Ameren Missouri's March 2016 to February 2019 MEEIA plan which included a portfolio of customer energy efficiency programs along with a rider to collect the program costs, the throughput disincentive, and a performance incentive from customers. The throughput disincentive recovery will replace the net shared benefits that were collected under the 2013 through 2015 MEEIA plan. The MEEIA rider will allow Ameren Missouri to collect the throughput disincentive without a traditional rate proceeding until such time as lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates will be based upon both forecasted program costs and throughput disincentive which will be annually reconciled to actual results. Beginning in March 2016, Ameren Missouri intends to invest $158 million over the three-year period in customer energy efficiency programs. In addition, similar to the MEEIA plan that ended in December 2015, the MoPSC's order approved a performance incentive that would provide $17 million decrease in Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy efficiency goals, including $27 million if 100% of the goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 25% of its energy efficiency goals before it earns a performance incentive.
The IEIMAIllinois’ electric delivery service revenue requirement beginning in January 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' 2016Illinois’ 2018 electric deliverydistribution service revenues will be based on its 20162018 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA'sIllinois performance-based formula ratemaking framework. The 20162018 revenue requirement is expected to be higher thancomparable to the 20152017 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of approximately 5%, and an expected increase in the monthly average yield of 30-year United States Treasury bonds.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 $6$8 million change in Ameren'sAmeren’s and Ameren Illinois'Illinois’ net income, based on its 2016Ameren Illinois’ 2018 projected year-end rate base.
In December 2015, the ICC issued an order with respectThe FEJA allows Ameren Illinois to Ameren Illinois’ annual update filing. The ICC approvedearn a $106 million increase inreturn on its electric energy-efficiency program investments. Ameren Illinois’ electric delivery service revenue requirement beginning in January 2016. These rates have affected and will continue to affect Ameren
Illinois' cash receipts during 2016, but will not be the sole determinant of its electric delivery service operating revenues, which will instead be largely determined by the IEIMA's 2016 revenue requirement reconciliation. The 2016 revenue requirement reconciliation,energy-efficiency investments are deferred as discussed above, is expected to result in a regulatory asset and earn a return at the company’s weighted-average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals.Pursuant to the FEJA, Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021 that will earn a return.Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments will be collected from customers through a rider; they will not be included in 2018.the IEIMA formula ratemaking framework. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ approved energy-efficiency program for 2018 through 2021.
In December 2015,January 2018, Ameren Illinois filed a request with the ICC issued a rate order that approved anseeking approval to increase inits annual revenues for Ameren Illinois' natural gas delivery service by $49 million, which included an estimated $42 million of $45 million. annual revenues that would otherwise be recovered under a QIP rider. The revenue increaserequest was based on a 9.6%10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.2$1.6 billion. The rate order was based on a 2016 future test year. The rate changes were in effect in January 2016. In addition, the rate order approved the VBA See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for residential and small nonresidential customers beginning in 2016.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 inis scheduled for the spring of 2016 and Ameren Missouri expects to incur $37 million of maintenance expenses in 2016. There was no refueling outage scheduled in 2015; however, $9 million in preparation costs were incurred in 2015 for the 2016 scheduled outage.2019. During the 20142017 refueling, Ameren Missouri incurred maintenance expenses of $36$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. In addition, Ameren Missouri may incur increased nonnuclear energy center maintenance costs in non-outage years.
Ameren and Ameren Missouri was engagedexpect an approximately $15 million decrease in litigation with an insurer to recover an unpaid liability insurance claim for the December 2005 breachannual interest charges as a result of the upper reservoirrepayment of $425 million of Ameren Missouri’s 6.40% senior secured notes at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. Asmaturity and issuance of December 31, 2015,$400 million 2.95% senior secured notes in 2017. In 2018, Ameren Missouri had an insurance receivable of $41 million. In February 2016, Ameren Missouri and the insurer reached a settlement that resulted in Ameren Missouri receiving $42 million in February 2016.
As we continueexpects to experience cost increases and to make infrastructure investments, Ameren Missourirefinance maturing long-term debt with lower-cost long-term debt, which would further reduce Ameren’s 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, as necessary, legislative solutions to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers, including Ameren Missouri's current efforts to advocate for a legislative solution to support Noranda's operations. These pressures include 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 distributed generation and storage, increased investments and expected future investments for environmental compliance, system reliability improvements, and newMissouri’s annual interest charges.
generation capacity, including renewable energy requirements. Increased | |
| • | As we continue to make infrastructure investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs and higher property 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, Noranda, Ameren Missouri's MEEIA plans, FERC return on equity complaint cases, and other pending requests filed with state and federal regulatory commissions, 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
WeIn 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.
| |
| • | 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 2022, we expect to incurmake significant capital expenditures in order to make investments to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and to comply with existing environmental regulations.distribution systems. We estimate that we will incurinvest up to $11.5$11.4 billion (Ameren Missouri – up to $4.3$4.5 billion; Ameren Illinois – up to $6.2$6.6 billion; ATXI – up to $1.0$0.3 billion) of capital expenditures during the period from 20162018 through 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 excluding the impact of the Clean Power Plan.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.
| |
| • | 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. TheseCertain 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, could be prohibitive ator 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. |
Ameren is evaluating the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation investment. In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until such time as legal appeals are concluded. Appeals are not expected to conclude prior to 2018. If the rule is ultimately upheld and implemented in substantially similar form to the rule when issued, 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. 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 fuel-diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as energy centers reach the end of their useful lives, continuation and expansion of the then-existing 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 2019,2021, 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 2019, $951 million and $457 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
In November 2015, Ameren (parent) issued $350 millionFederal income tax legislation enacted under the TCJA will have significant impacts on our results of 2.70% senior unsecured notes due November 15, 2020operations, financial position, liquidity, and $350 millionfinancial 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 3.65% senior unsecured notes due February 15, 2026. Ameren used the proceeds to pay a portion of short-term debt consisting of commercial paper issuances.increasing Ameren’s near-term projected income tax liabilities. Ameren expects to incur interest chargeslargely 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 $22 million annually related to these issuances.
In December 2015, athe reduced federal statutory corporate income tax law was enacted that authorized the continued use of bonus depreciation that allows for an acceleration of deductions for tax purposes at a rate of 50% for 2015, 2016, and 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. Bonus depreciation is expected to increasebe a decrease in operating cash flow through at least 2020. flows. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers.Ameren expects 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 on Amerenapproximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois and ATXI will vary based on investment levels at each company.– $0.5 billion).
As of December 31, 2015,2017, Ameren had $453$235 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $39 million and Ameren Illinois – $131 million) and $144$120 million in federal and state income tax credit carryforwards. These carryforwards (Ameren Missouri – $26 million and Ameren Illinois – $2 million). In addition, Ameren has $37 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 until 2019 and Ameren Illinois until 2021. 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, wouldbeginning in 2018.
be available to fund ATXI transmission investments.
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-
In October 2015, Ameren’s board of directors declared a fourth quarter dividend of 42.5 cents per common share, a 3.7% increase from the prior quarterly dividend rate of 41 cents per share, resulting
term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in an annualized equivalent dividend rate of $1.70 per share.
The use of cash from operating activitiesaccordance with ratemaking frameworks. Ameren Missouri and from short-term borrowingsAmeren Illinois expect to fund cash flows needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital expenditurescontributions from Ameren (parent), with the intent to maintain strong financial metrics and other long-term investments may periodically resultan equity ratio around 50%, as calculated in a working capital deficit, defined by current liabilities exceeding current assets, as was the case at December 31, 2015, for Ameren. The working capital deficit as of December 31, 2015, was primarily the result of current maturities of long-term debt and commercial paper issuances. The Ameren Companies had $301 million of commercial paper issuances outstanding as of December 31, 2015. With the Credit Agreements and cash and cash equivalents available, the Ameren Companies had access to $1.8 billion of credit capacity available, and $2.1 billion of liquidity at December 31, 2015.
In February 2016, $260 million principal amount of Ameren Missouri's 5.40% senior secured notes matured and were repaid using available cash and commercial paper borrowings.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.
|
| | |
| Accounting Estimate | | Uncertainties Affecting Application |
Regulatory Mechanisms and Cost Recovery
We defer costs and recognize revenue in accordance with authoritative accounting guidance, and make investmentsrevenues that we assume will be collectedintend 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
We determine whichThe 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 recoverablerecovered 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 reviewing previous rulings byour regulatory authorities in jurisdictions where we operate and any other factorscommissions, legislation, or historical experience, as well as discussions with legal counsel. Regulatory liabilities represent revenues received from customers to fund expected costs that may indicate whether cost recovery is probable.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 in accordance with authoritative accounting guidance regardingfor the benefit plans.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 ratesrate
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 all available evidence, includingthe nature of the litigation, the claim or assessment, opinions or views of legal counsel, and the expected outcome of potential litigation.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
Following authoritative accounting guidance, weWe record thea 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, or enacted tax rates or amounts subject to income tax, the form, structure, and timing of asset or stock sales or dispositions, change 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,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, 20152017.
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 delivery service business.distribution 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. As such, 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.
| |
| 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 1%100 basis points on variable-rate debt outstanding at December 31, 2015:2017:
| | | | | Interest Expense | | Net Income(a) | | Interest Expense | | Net Income(a) |
| Ameren | $ | 5 |
| $ | (3 | ) | $ | 7 |
| $ | (5 | ) |
| Ameren Missouri | | 2 |
| | (1 | ) | | 2 |
| | (2 | ) |
| Ameren Illinois | | (b) |
| | (b) |
| | 1 |
| | (1 | ) |
| |
| (a) | Calculations are based on an estimatedthe 2018 statutory tax raterates of 38%27%, 37%25%, and 37%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 $6$8 million change in Ameren'sAmeren’s and Ameren Illinois'Illinois’ net income, based on its 20162018 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, 2015.2017.
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, 2015,2017, no nonaffiliated customer represented more than 10%, in the aggregate, 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' delivery serviceIllinois’ 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 delivery servicedistribution and purchased receivables. As of December 31, 2015,2017, Ameren Illinois'Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $25$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 20162018 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, 2015,2017, this fund was invested in domestic equity securities (66%) and debt securities (34%(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 that are used to support Ameren’s deferred compensation plans. 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 regulated 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 2018.2020. In 2015,2017, acting in its role as the provider of last resort, Ameren Illinois supplied approximately 26%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 a multiyear agreementagreements with multiple suppliers to purchase ultra-low-sulfur coal through 20182021 to comply with environmental regulations. The coal contract is with a single supplier. Disruptions to the deliveries of that ultra-low-sulfur coal from thea supplier could compromise Ameren Missouri'sMissouri’s ability to operate in compliance with emission standards. Other sourcesThe 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, or purchase emission allowances to achieve compliance with environmental regulations.regulations, or purchase power necessary to meet demand.
Currently, theThe 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 decidebelieve 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.implement. See Note 9 – Callaway Energy Center under Part II, Item 8, of this report for additional information.
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, 2015.2017. 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 | $ | (28 | ) | | $ | (185 | ) | | $ | (213 | ) | $ | (4 | ) | | $ | (180 | ) | | $ | (184 | ) |
| Contracts realized or otherwise settled during the period | 15 |
| | 41 |
| | 56 |
| (3 | ) | | 4 |
| | 1 |
|
| Fair value of new contracts entered into during the period | 6 |
| | (19 | ) | | (13 | ) | 11 |
| | (7 | ) | | 4 |
|
| Other changes in fair value | (20 | ) | | (56 | ) | | (76 | ) | 4 |
| | (34 | ) | | (30 | ) |
| Fair value of contracts outstanding at end of year, net | $ | (27 | ) | | $ | (219 | ) | | $ | (246 | ) | $ | 8 |
| | $ | (217 | ) | | $ | (209 | ) |
The following table presents maturities of derivative contracts as of December 31, 2015, by2017, 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 | $ | (23 | ) | | $ | (6 | ) | | $ | — |
| | $ | — |
| | $ | (29 | ) | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Level 2(a) | (5 | ) | | (6 | ) | | (2 | ) | | — |
| | (13 | ) | (3 | ) | | (3 | ) | | — |
| | — |
| | (6 | ) |
Level 3(b) | 15 |
| | — |
| | — |
| | — |
| | 15 |
| 8 |
| | 2 |
| | — |
| | — |
| | 10 |
|
| Total | $ | (13 | ) | | $ | (12 | ) | | $ | (2 | ) | | $ | — |
| | $ | (27 | ) | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Ameren Illinois: |
| |
| |
| |
| |
|
|
| |
|
| |
|
| |
|
| |
|
|
| Level 1 | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) |
Level 2(a) | (31 | ) | | (17 | ) | | — |
| | — |
| | (48 | ) | (10 | ) | | (7 | ) | | (1 | ) | | — |
| | (18 | ) |
Level 3(b) | (12 | ) | | (24 | ) | | (24 | ) | | (110 | ) | | (170 | ) | (14 | ) | | (30 | ) | | (29 | ) | | (125 | ) | | (198 | ) |
| Total | $ | (43 | ) | | $ | (42 | ) | | $ | (24 | ) | | $ | (110 | ) | | $ | (219 | ) | $ | (25 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (217 | ) |
| Ameren: | | | | | | | | | | | | | | | | | | |
| Level 1 | $ | (23 | ) | | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | (30 | ) | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
Level 2(a) | (36 | ) | | (23 | ) | | (2 | ) | | — |
| | (61 | ) | (13 | ) | | (10 | ) | | (1 | ) | | — |
| | (24 | ) |
Level 3(b) | 3 |
| | (24 | ) | | (24 | ) | | (110 | ) | | (155 | ) | (6 | ) | | (28 | ) | | (29 | ) | | (125 | ) | | (188 | ) |
| Total | $ | (56 | ) | | $ | (54 | ) | | $ | (26 | ) | | $ | (110 | ) | | $ | (246 | ) | $ | (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 atthe Company as of December 31, 20152017 and 2014,2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2017, 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, 2015,2017, 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 26, 201628, 2018
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 atas of December 31, 20152017 and 2014,2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015,2017, 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 26, 2016
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 at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, 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 26, 201628, 2018
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.
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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Operating Revenues: |
| |
| | |
| |
| | |
| Electric | $ | 5,180 |
| | $ | 4,913 |
| | $ | 4,832 |
| $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
|
| Gas | 918 |
| | 1,140 |
| | 1,006 |
| |
| Natural gas | | 867 |
| | 880 |
| | 918 |
|
| Total operating revenues | 6,098 |
| | 6,053 |
| | 5,838 |
| 6,177 |
| | 6,076 |
| | 6,098 |
|
| Operating Expenses: |
| |
| | |
| |
| | |
| Fuel | 878 |
| | 826 |
| | 845 |
| 737 |
| | 745 |
| | 878 |
|
| Purchased power | 514 |
| | 461 |
| | 508 |
| 638 |
| | 621 |
| | 514 |
|
| Gas purchased for resale | 415 |
| | 615 |
| | 526 |
| |
| Natural gas purchased for resale | | 311 |
| | 341 |
| | 415 |
|
| Other operations and maintenance | 1,694 |
| | 1,684 |
| | 1,611 |
| 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 | 796 |
| | 745 |
| | 706 |
| 896 |
| | 845 |
| | 796 |
|
| Taxes other than income taxes | 473 |
| | 468 |
| | 458 |
| 477 |
| | 467 |
| | 473 |
|
| Total operating expenses | 4,839 |
| | 4,799 |
| | 4,654 |
| 4,719 |
| | 4,695 |
| | 4,839 |
|
| Operating Income | 1,259 |
| | 1,254 |
| | 1,184 |
| 1,458 |
| | 1,381 |
| | 1,259 |
|
| Other Income and Expenses: | | | | | | | | | | |
| Miscellaneous income | 74 |
| | 79 |
| | 69 |
| 59 |
| | 74 |
| | 74 |
|
| Miscellaneous expense | 30 |
| | 22 |
| | 26 |
| 21 |
| | 32 |
| | 30 |
|
| Total other income | 44 |
| | 57 |
| | 43 |
| 38 |
| | 42 |
| | 44 |
|
| Interest Charges | 355 |
| | 341 |
| | 398 |
| 391 |
| | 382 |
| | 355 |
|
| Income Before Income Taxes | 948 |
| | 970 |
| | 829 |
| 1,105 |
| | 1,041 |
| | 948 |
|
| Income Taxes | 363 |
| | 377 |
| | 311 |
| 576 |
| | 382 |
| | 363 |
|
| Income from Continuing Operations | 585 |
| | 593 |
| | 518 |
| 529 |
| | 659 |
| | 585 |
|
| Income (Loss) from Discontinued Operations, Net of Taxes (Note 16) | 51 |
| | (1 | ) | | (223 | ) | |
| Income from Discontinued Operations, Net of Taxes | | — |
| | — |
| | 51 |
|
| Net Income | 636 |
| | 592 |
| | 295 |
| 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 | 579 |
| | 587 |
| | 512 |
| 523 |
| | 653 |
| | 579 |
|
| Discontinued Operations | 51 |
| | (1 | ) | | (223 | ) | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 630 |
| | $ | 586 |
| | $ | 289 |
| $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | | | | | | |
| Earnings (Loss) per Common Share – Basic: | | | | | | |
| Earnings per Common Share – Basic: | | | | | | |
| Continuing Operations | $ | 2.39 |
| | $ | 2.42 |
| | $ | 2.11 |
| $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.39 |
|
| Discontinued Operations | 0.21 |
| | — |
| | (0.92 | ) | — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Basic | $ | 2.60 |
| | $ | 2.42 |
| | $ | 1.19 |
| $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.60 |
|
| | | | | | | | | | | |
| Earnings (Loss) per Common Share – Diluted: | | | | | | |
| Earnings per Common Share – Diluted: | | | | | | |
| Continuing Operations | $ | 2.38 |
| | $ | 2.40 |
| | $ | 2.10 |
| $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.38 |
|
| Discontinued Operations | 0.21 |
| | — |
| | (0.92 | ) | — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Diluted | $ | 2.59 |
| | $ | 2.40 |
| | $ | 1.18 |
| $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.59 |
|
| | | | | | | | | | | |
| Dividends per Common Share | $ | 1.655 |
| | $ | 1.610 |
| | $ | 1.600 |
| $ | 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 | 243.6 |
| | 244.4 |
| | 244.5 |
| 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) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | | | | | |
| Income from Continuing Operations | $ | 585 |
| | $ | 593 |
| | $ | 518 |
|
| Other Comprehensive Income from Continuing Operations, Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $16, respectively | 6 |
| | (12 | ) | | 30 |
|
| Comprehensive Income from Continuing Operations | 591 |
| | 581 |
| | 548 |
|
| Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 585 |
| | 575 |
| | 542 |
|
| | | | | | |
| Income (Loss) from Discontinued Operations, Net of Taxes | 51 |
| | (1 | ) | | (223 | ) |
| Other Comprehensive Loss from Discontinued Operations, Net of Income Taxes (Benefit) of $-, $-, and $(10), respectively | — |
| | — |
| | (18 | ) |
| Comprehensive Income (Loss) from Discontinued Operations | 51 |
| | (1 | ) | | (241 | ) |
| Less: Comprehensive Income from Discontinued Operations Attributable to Noncontrolling Interest | — |
| | — |
| | 1 |
|
| Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Common Shareholders | 51 |
| | (1 | ) | | (242 | ) |
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 636 |
| | $ | 574 |
| | $ | 300 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Income from Continuing Operations | $ | 529 |
| | $ | 659 |
| | $ | 585 |
|
| Other Comprehensive Income (Loss) from Continuing Operations, Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $3, respectively | 5 |
| | (20 | ) | | 6 |
|
| Comprehensive Income from Continuing Operations | 534 |
| | 639 |
| | 591 |
|
| Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 528 |
| | 633 |
| | 585 |
|
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
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, |
| | 2015 | | 2014 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 292 |
| | $ | 5 |
| $ | 10 |
| | $ | 9 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $19 and $21, respectively) | 388 |
| | 423 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively) | | 445 |
| | 437 |
|
| Unbilled revenue | 239 |
| | 265 |
| 323 |
| | 295 |
|
| Miscellaneous accounts and notes receivable | 98 |
| | 81 |
| 70 |
| | 63 |
|
| Materials and supplies | 538 |
| | 524 |
| |
| Inventories | | 522 |
| | 527 |
|
| Current regulatory assets | 260 |
| | 295 |
| 144 |
| | 149 |
|
| Other current assets | 88 |
| | 86 |
| 98 |
| | 113 |
|
| Assets of discontinued operations (Note 16) | 14 |
| | 15 |
| |
| Total current assets | 1,917 |
| | 1,694 |
| 1,612 |
| | 1,593 |
|
| Property and Plant, Net | 18,799 |
| | 17,424 |
| |
| Property, Plant, and Equipment, Net | | 21,466 |
| | 20,113 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 556 |
| | 549 |
| 704 |
| | 607 |
|
| Goodwill | 411 |
| | 411 |
| 411 |
| | 411 |
|
| Regulatory assets | 1,382 |
| | 1,582 |
| 1,230 |
| | 1,437 |
|
| Other assets | 575 |
| | 629 |
| 522 |
| | 538 |
|
| Total investments and other assets | 2,924 |
| | 3,171 |
| 2,867 |
| | 2,993 |
|
| TOTAL ASSETS | $ | 23,640 |
| | $ | 22,289 |
| $ | 25,945 |
| | $ | 24,699 |
|
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 395 |
| | $ | 120 |
| $ | 841 |
| | $ | 681 |
|
| Short-term debt | 301 |
| | 714 |
| 484 |
| | 558 |
|
| Accounts and wages payable | 777 |
| | 711 |
| 902 |
| | 805 |
|
| Taxes accrued | 43 |
| | 46 |
| 52 |
| | 46 |
|
| Interest accrued | 89 |
| | 85 |
| 99 |
| | 93 |
|
| Customer deposits | | 108 |
| | 107 |
|
| Current regulatory liabilities | 80 |
| | 106 |
| 128 |
| | 110 |
|
| Other current liabilities | 379 |
| | 434 |
| 326 |
| | 274 |
|
| Liabilities of discontinued operations (Note 16) | 29 |
| | 33 |
| |
| Total current liabilities | 2,093 |
| | 2,249 |
| 2,940 |
| | 2,674 |
|
| Long-term Debt, Net | 6,880 |
| | 6,085 |
| 7,094 |
| | 6,595 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 3,885 |
| | 3,571 |
| 2,506 |
| | 4,264 |
|
| Accumulated deferred investment tax credits | 60 |
| | 64 |
| 49 |
| | 55 |
|
| Regulatory liabilities | 1,905 |
| | 1,850 |
| 4,387 |
| | 1,985 |
|
| Asset retirement obligations | 618 |
| | 396 |
| 638 |
| | 635 |
|
| Pension and other postretirement benefits | 580 |
| | 705 |
| 545 |
| | 769 |
|
| Other deferred credits and liabilities | 531 |
| | 514 |
| 460 |
| | 477 |
|
| Total deferred credits and other liabilities | 7,579 |
| | 7,100 |
| 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 | 5,616 |
| | 5,617 |
| 5,540 |
| | 5,556 |
|
| Retained earnings | 1,331 |
| | 1,103 |
| 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (3 | ) | | (9 | ) | (18 | ) | | (23 | ) |
| Total Ameren Corporation shareholders’ equity | 6,946 |
| | 6,713 |
| 7,184 |
| | 7,103 |
|
| Noncontrolling Interests | 142 |
| | 142 |
| 142 |
| | 142 |
|
| Total equity | 7,088 |
| | 6,855 |
| 7,326 |
| | 7,245 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 23,640 |
| | $ | 22,289 |
| $ | 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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 636 |
| | $ | 592 |
| | $ | 295 |
| $ | 529 |
| | $ | 659 |
| | $ | 636 |
|
| Loss (Income) from discontinued operations, net of tax | (51 | ) | | 1 |
| | 223 |
| |
| 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 | 777 |
| | 710 |
| | 666 |
| 876 |
| | 835 |
| | 777 |
|
| Amortization of nuclear fuel | 97 |
| | 81 |
| | 71 |
| 76 |
| | 88 |
| | 97 |
|
| Amortization of debt issuance costs and premium/discounts | 22 |
| | 22 |
| | 24 |
| 22 |
| | 22 |
| | 22 |
|
| Deferred income taxes and investment tax credits, net | 369 |
| | 451 |
| | 410 |
| 539 |
| | 386 |
| | 369 |
|
| Allowance for equity funds used during construction | (30 | ) | | (34 | ) | | (37 | ) | (24 | ) | | (27 | ) | | (30 | ) |
| Stock-based compensation costs | 24 |
| | 25 |
| | 27 |
| |
| Share-based compensation costs | | 17 |
| | 17 |
| | 24 |
|
| Other | (10 | ) | | (24 | ) | | 23 |
| (10 | ) | | 4 |
| | (10 | ) |
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | 83 |
| | 31 |
| | (60 | ) | (53 | ) | | (71 | ) | | 83 |
|
| Materials and supplies | (14 | ) | | 3 |
| | 60 |
| |
| Inventories | | 17 |
| | 11 |
| | (14 | ) |
| Accounts and wages payable | (2 | ) | | 10 |
| | 81 |
| 32 |
| | 19 |
| | (2 | ) |
| Taxes accrued | (24 | ) | | (44 | ) | | (195 | ) | 55 |
| | 13 |
| | (22 | ) |
| Regulatory assets and liabilities | 94 |
| | (281 | ) | | 29 |
| 36 |
| | 215 |
| | 94 |
|
| Assets, other | 53 |
| | 30 |
| | 20 |
| 20 |
| | (22 | ) | | 46 |
|
| Liabilities, other | (56 | ) | | (28 | ) | | (14 | ) | (7 | ) | | (9 | ) | | (44 | ) |
| Pension and other postretirement benefits | (9 | ) | | (10 | ) | | (28 | ) | (21 | ) | | (16 | ) | | (9 | ) |
| Counterparty collateral, net | (7 | ) | | 22 |
| | 41 |
| |
| Net cash provided by operating activities – continuing operations | 2,021 |
| | 1,557 |
| | 1,636 |
| 2,104 |
| | 2,124 |
| | 2,035 |
|
| Net cash provided (used in) by operating activities – discontinued operations | (4 | ) | | (6 | ) | | 57 |
| |
| Net cash used in operating activities – discontinued operations | | — |
| | (1 | ) | | (4 | ) |
| Net cash provided by operating activities | 2,017 |
| | 1,551 |
| | 1,693 |
| 2,104 |
| | 2,123 |
| | 2,031 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (1,917 | ) | | (1,785 | ) | | (1,379 | ) | (2,132 | ) | | (2,076 | ) | | (1,917 | ) |
| Nuclear fuel expenditures | (52 | ) | | (74 | ) | | (45 | ) | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (363 | ) | | (405 | ) | | (214 | ) | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 349 |
| | 391 |
| | 196 |
| 396 |
| | 377 |
| | 349 |
|
| Proceeds from note receivable – Marketing Company | 20 |
| | 95 |
| | 6 |
| |
| Contributions to note receivable – Marketing Company | (8 | ) | | (89 | ) | | (5 | ) | |
| Other | 20 |
| | 11 |
| | 1 |
| 7 |
| | 5 |
| | 32 |
|
| Net cash used in investing activities – continuing operations | (1,951 | ) | | (1,856 | ) | | (1,440 | ) | (2,205 | ) | | (2,141 | ) | | (1,951 | ) |
| Net cash provided by (used in) investing activities – discontinued operations | (25 | ) | | 139 |
| | (283 | ) | |
| Net cash used in investing activities – discontinued operations | | — |
| | — |
| | (25 | ) |
| Net cash used in investing activities | (1,976 | ) | | (1,717 | ) | | (1,723 | ) | (2,205 | ) | | (2,141 | ) | | (1,976 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Dividends on common stock | (402 | ) | | (390 | ) | | (388 | ) | (431 | ) | | (416 | ) | | (402 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt, net | (413 | ) | | 346 |
| | 368 |
| (74 | ) | | 257 |
| | (413 | ) |
| Maturities, redemptions and repurchases of long-term debt | (120 | ) | | (697 | ) | | (399 | ) | |
| Redemptions, repurchases, and maturities of long-term debt | | (681 | ) | | (395 | ) | | (120 | ) |
| Issuances of long-term debt | 1,197 |
| | 898 |
| | 278 |
| 1,345 |
| | 389 |
| | 1,197 |
|
| Capital issuance costs | (12 | ) | | (11 | ) | | (2 | ) | |
| Debt issuance costs | | (11 | ) | | (9 | ) | | (12 | ) |
| Share-based payments | | (39 | ) | | (83 | ) | | (12 | ) |
| Other | 2 |
| | 1 |
| | — |
| (1 | ) | | (2 | ) | | — |
|
| Net cash provided by (used in) financing activities – continuing operations | 246 |
| | 141 |
| | (149 | ) | 102 |
| | (265 | ) | | 232 |
|
| Net change in cash and cash equivalents | 287 |
| | (25 | ) | | (179 | ) | 1 |
| | (283 | ) | | 287 |
|
| Cash and cash equivalents at beginning of year | 5 |
| | 30 |
| | 209 |
| 9 |
| | 292 |
| | 5 |
|
| Cash and cash equivalents at end of year | $ | 292 |
| | $ | 5 |
| | $ | 30 |
| $ | 10 |
| | $ | 9 |
| | $ | 292 |
|
| | | | | | | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | | | | | | |
| Interest (net of $17, $18, and $37 capitalized, respectively) | $ | 335 |
| | $ | 333 |
| | $ | 393 |
| |
| Interest (net of $14, $15, and $17 capitalized, respectively) | | $ | 370 |
| | $ | 358 |
| | $ | 335 |
|
| Income taxes, net | (15 | ) | | (27 | ) | | 8 |
| (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, |
| | 2015 | | 2014 | | 2013 | 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 | 5,617 |
| | 5,632 |
| | 5,616 |
| 5,556 |
| | 5,616 |
| | 5,617 |
|
| Stock-based compensation activity | (1 | ) | | (15 | ) | | 16 |
| |
| Share-based compensation activity | | (16 | ) | | (60 | ) | | (1 | ) |
| Other paid-in capital, end of year | 5,616 |
| | 5,617 |
| | 5,632 |
| 5,540 |
| | 5,556 |
| | 5,616 |
|
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 1,103 |
| | 907 |
| | 1,006 |
| 1,568 |
| | 1,331 |
| | 1,103 |
|
| Net income attributable to Ameren common shareholders | 630 |
| | 586 |
| | 289 |
| 523 |
| | 653 |
| | 630 |
|
| Dividends | (402 | ) | | (390 | ) | | (388 | ) | (431 | ) | | (416 | ) | | (402 | ) |
| Retained earnings, end of year | 1,331 |
| | 1,103 |
| | 907 |
| 1,660 |
| | 1,568 |
| | 1,331 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | | | | | | |
| Derivative financial instruments, beginning of year | — |
| | — |
| | 25 |
| |
| Change in derivative financial instruments | — |
| | — |
| | (21 | ) | |
| Divestiture of derivative financial instruments (Note 16) | — |
| | — |
| | (4 | ) | |
| Derivative financial instruments, end of year | — |
| | — |
| | — |
| |
| Deferred retirement benefit costs, beginning of year | (9 | ) | | 3 |
| | (33 | ) | (23 | ) | | (3 | ) | | (9 | ) |
| Change in deferred retirement benefit costs | 6 |
| | (12 | ) | | 29 |
| 5 |
| | (20 | ) | | 6 |
|
| Divestiture of deferred retirement benefit costs (Note 16) | — |
| | — |
| | 7 |
| |
| Deferred retirement benefit costs, end of year | (3 | ) | | (9 | ) | | 3 |
| (18 | ) | | (23 | ) | | (3 | ) |
| Total accumulated other comprehensive income (loss), end of year | (3 | ) | | (9 | ) | | 3 |
| |
| Total accumulated other comprehensive loss, end of year | | (18 | ) | | (23 | ) | | (3 | ) |
| Total Ameren Corporation Shareholders’ Equity | $ | 6,946 |
| | $ | 6,713 |
| | $ | 6,544 |
| $ | 7,184 |
| | $ | 7,103 |
| | $ | 6,946 |
|
| | | | | | | | | | | |
| Noncontrolling Interests: | | | | | | | | | | |
| Beginning of year | 142 |
| | 142 |
| | 151 |
| 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 | ) |
| Divestiture of noncontrolling interest (Note 16) | — |
| | — |
| | (9 | ) | |
| Noncontrolling interests, end of year | 142 |
| | 142 |
| | 142 |
| 142 |
| | 142 |
| | 142 |
|
| Total Equity | $ | 7,088 |
| | $ | 6,855 |
| | $ | 6,686 |
| $ | 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, |
| | 2015 |
| 2014 | | 2013 | 2017 |
| 2016 | | 2015 |
| Operating Revenues: |
|
|
| | |
|
|
| | |
| Electric | $ | 3,470 |
|
| $ | 3,388 |
| | $ | 3,379 |
| $ | 3,413 |
|
| $ | 3,394 |
| | $ | 3,470 |
|
| Gas | 137 |
|
| 164 |
| | 161 |
| |
| Natural gas | | 126 |
|
| 128 |
| | 137 |
|
| Other | 2 |
|
| 1 |
| | 1 |
| — |
|
| 1 |
| | 2 |
|
| Total operating revenues | 3,609 |
|
| 3,553 |
| | 3,541 |
| 3,539 |
|
| 3,523 |
| | 3,609 |
|
| Operating Expenses: |
|
|
| | |
|
|
| | |
| Fuel | 878 |
|
| 826 |
| | 845 |
| 737 |
|
| 745 |
| | 878 |
|
| Purchased power | 111 |
|
| 126 |
| | 133 |
| 245 |
|
| 252 |
| | 111 |
|
| Gas purchased for resale | 57 |
| | 82 |
| | 78 |
| |
| Natural gas purchased for resale | | 47 |
| | 49 |
| | 57 |
|
| Other operations and maintenance | 925 |
| | 939 |
| | 909 |
| 902 |
| | 893 |
| | 925 |
|
| Provision for Callaway construction and operating license (Note 2) | 69 |
| | — |
| | — |
| |
| Provision for Callaway construction and operating license | | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 492 |
| | 473 |
| | 454 |
| 533 |
| | 514 |
| | 492 |
|
| Taxes other than income taxes | 335 |
| | 322 |
| | 319 |
| 328 |
| | 325 |
| | 335 |
|
| Total operating expenses | 2,867 |
| | 2,768 |
| | 2,738 |
| 2,792 |
| | 2,778 |
| | 2,867 |
|
| Operating Income | 742 |
| | 785 |
| | 803 |
| 747 |
| | 745 |
| | 742 |
|
| Other Income and Expenses: | | | | | | | | | | |
| Miscellaneous income | 52 |
| | 60 |
| | 58 |
| 48 |
| | 52 |
| | 52 |
|
| Miscellaneous expense | 11 |
| | 12 |
| | 11 |
| 8 |
| | 10 |
| | 11 |
|
| Total other income | 41 |
| | 48 |
| | 47 |
| 40 |
| | 42 |
| | 41 |
|
| Interest Charges | 219 |
| | 211 |
| | 210 |
| 207 |
| | 211 |
| | 219 |
|
| Income Before Income Taxes | 564 |
| | 622 |
| | 640 |
| 580 |
| | 576 |
| | 564 |
|
| Income Taxes | 209 |
| | 229 |
| | 242 |
| 254 |
| | 216 |
| | 209 |
|
| Net Income | 355 |
| | 393 |
| | 398 |
| 326 |
| | 360 |
| | 355 |
|
| Other Comprehensive Income | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Comprehensive Income | $ | 355 |
| | $ | 393 |
| | $ | 398 |
| $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
| Net Income | $ | 355 |
| | $ | 393 |
| | $ | 398 |
| $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
| 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 352 |
| | $ | 390 |
| | $ | 395 |
| $ | 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, |
| | 2015 | | 2014 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 199 |
| | $ | 1 |
| $ | — |
| | $ | — |
|
| Advances to money pool | 36 |
| | — |
| — |
| | 161 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $7 and $8, respectively) | 174 |
| | 190 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively) | | 200 |
| | 187 |
|
| Accounts receivable – affiliates | 54 |
| | 65 |
| 11 |
| | 12 |
|
| Unbilled revenue | 128 |
| | 146 |
| 165 |
| | 154 |
|
| Miscellaneous accounts and notes receivable | 78 |
| | 35 |
| 35 |
| | 14 |
|
| Materials and supplies | 387 |
| | 347 |
| |
| Inventories | | 388 |
| | 392 |
|
| Current regulatory assets | 89 |
| | 163 |
| 56 |
| | 35 |
|
| Other current assets | 41 |
| | 43 |
| 50 |
| | 49 |
|
| Total current assets | 1,186 |
| | 990 |
| 905 |
| | 1,004 |
|
| Property and Plant, Net | 11,183 |
| | 10,867 |
| |
| Property, Plant, and Equipment, Net | | 11,751 |
| | 11,478 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 556 |
| | 549 |
| 704 |
| | 607 |
|
| Regulatory assets | 605 |
| | 695 |
| 395 |
| | 619 |
|
| Other assets | 321 |
| | 373 |
| 288 |
| | 327 |
|
| Total investments and other assets | 1,482 |
| | 1,617 |
| 1,387 |
| | 1,553 |
|
| TOTAL ASSETS | $ | 13,851 |
| | $ | 13,474 |
| $ | 14,043 |
| | $ | 14,035 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 266 |
| | $ | 120 |
| $ | 384 |
| | $ | 431 |
|
| Short-term debt | — |
| | 97 |
| 39 |
| | — |
|
| Accounts and wages payable | 417 |
| | 405 |
| 475 |
| | 444 |
|
| Accounts payable – affiliates | 56 |
| | 56 |
| 60 |
| | 68 |
|
| Taxes accrued | 31 |
| | 32 |
| 30 |
| | 30 |
|
| Interest accrued | 59 |
| | 58 |
| 54 |
| | 54 |
|
| Current regulatory liabilities | 28 |
| | 18 |
| 19 |
| | 12 |
|
| Other current liabilities | 120 |
| | 117 |
| 103 |
| | 123 |
|
| Total current liabilities | 977 |
| | 903 |
| 1,164 |
| | 1,162 |
|
| Long-term Debt, Net | 3,844 |
| | 3,861 |
| 3,577 |
| | 3,563 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 2,844 |
| | 2,757 |
| 1,650 |
| | 3,013 |
|
| Accumulated deferred investment tax credits | 58 |
| | 61 |
| 48 |
| | 53 |
|
| Regulatory liabilities | 1,172 |
| | 1,147 |
| 2,664 |
| | 1,215 |
|
| Asset retirement obligations | 612 |
| | 389 |
| 634 |
| | 629 |
|
| Pension and other postretirement benefits | 234 |
| | 274 |
| 213 |
| | 291 |
|
| Other deferred credits and liabilities | 28 |
| | 30 |
| 12 |
| | 19 |
|
| Total deferred credits and other liabilities | 4,948 |
| | 4,658 |
| 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 | 1,822 |
| | 1,569 |
| 1,858 |
| | 1,828 |
|
| Preferred stock | 80 |
| | 80 |
| 80 |
| | 80 |
|
| Retained earnings | 1,669 |
| | 1,892 |
| 1,632 |
| | 1,671 |
|
| Total shareholders’ equity | 4,082 |
| | 4,052 |
| 4,081 |
| | 4,090 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 13,851 |
| | $ | 13,474 |
| $ | 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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 355 |
| | $ | 393 |
| | $ | 398 |
| $ | 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 | 476 |
| | 442 |
| | 419 |
| 514 |
| | 506 |
| | 476 |
|
| Amortization of nuclear fuel | 97 |
| | 81 |
| | 71 |
| 76 |
| | 88 |
| | 97 |
|
| FAC prudence review charges | — |
| | — |
| | 26 |
| |
| Amortization of debt issuance costs and premium/discounts | 6 |
| | 7 |
| | 7 |
| 6 |
| | 6 |
| | 6 |
|
| Deferred income taxes and investment tax credits, net | 82 |
| | 245 |
| | 65 |
| 82 |
| | 179 |
| | 82 |
|
| Allowance for equity funds used during construction | (22 | ) | | (32 | ) | | (31 | ) | (21 | ) | | (23 | ) | | (22 | ) |
| Other | 2 |
| | 3 |
| | 1 |
| 4 |
| | 5 |
| | 2 |
|
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | 72 |
| | (10 | ) | | (59 | ) | (46 | ) | | 5 |
| | 72 |
|
| Materials and supplies | (39 | ) | | 8 |
| | 45 |
| |
| Inventories | | 18 |
| | (4 | ) | | (39 | ) |
| Accounts and wages payable | 3 |
| | 25 |
| | 42 |
| 27 |
| | (18 | ) | | 3 |
|
| Taxes accrued | 1 |
| | (197 | ) | | 100 |
| (1 | ) | | 11 |
| | 1 |
|
| Regulatory assets and liabilities | 117 |
| | (68 | ) | | 68 |
| 26 |
| | 84 |
| | 117 |
|
| Assets, other | 26 |
| | 52 |
| | 18 |
| 30 |
| | (25 | ) | | 26 |
|
| Liabilities, other | 4 |
| | — |
| | (29 | ) | (23 | ) | | (1 | ) | | 4 |
|
| Pension and other postretirement benefits | (2 | ) | | 1 |
| | 2 |
| (2 | ) | | (4 | ) | | (2 | ) |
| Net cash provided by operating activities | 1,247 |
| | 950 |
| | 1,143 |
| 1,016 |
| | 1,169 |
| | 1,247 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (622 | ) | | (747 | ) | | (648 | ) | (773 | ) | | (738 | ) | | (622 | ) |
| Nuclear fuel expenditures | (52 | ) | | (74 | ) | | (45 | ) | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (363 | ) | | (405 | ) | | (214 | ) | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 349 |
| | 391 |
| | 196 |
| 396 |
| | 377 |
| | 349 |
|
| Money pool advances, net | (36 | ) | | — |
| | 24 |
| 161 |
| | (125 | ) | | (36 | ) |
| Other | — |
| | (2 | ) | | — |
| 7 |
| | (1 | ) | | — |
|
| Net cash used in investing activities | (724 | ) | | (837 | ) | | (687 | ) | (685 | ) | | (934 | ) | | (724 | ) |
| Cash Flows From Financing Activities: | | | | | | | | | | |
| Dividends on common stock | (575 | ) | | (340 | ) | | (460 | ) | (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 | ) | | 105 |
| |
| Redemptions, repurchases, and maturities of long-term debt | (120 | ) | | (109 | ) | | (249 | ) | (431 | ) | | (266 | ) | | (120 | ) |
| Issuances of long-term debt | 249 |
| | 350 |
| | — |
| 399 |
| | 149 |
| | 249 |
|
| Capital issuance costs | (3 | ) | | (3 | ) | | — |
| (3 | ) | | (3 | ) | | (3 | ) |
| Capital contribution from parent | 224 |
| | 215 |
| | 4 |
| 30 |
| | 44 |
| | 224 |
|
| Net cash used in financing activities | (325 | ) | | (113 | ) | | (603 | ) | (331 | ) | | (434 | ) | | (325 | ) |
| Net change in cash and cash equivalents | 198 |
| | — |
| | (147 | ) | — |
| | (199 | ) | | 198 |
|
| Cash and cash equivalents at beginning of year | 1 |
| | 1 |
| | 148 |
| — |
| | 199 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | 199 |
| | $ | 1 |
| | $ | 1 |
| $ | — |
| | $ | — |
| | $ | 199 |
|
| | | | | | | | | | | |
Noncash financing activity – capital contribution from parent | $ | 38 |
| | $ | 9 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 38 |
|
| | | | | | | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | | |
| Interest (net of $12, $16, and $16 capitalized, respectively) | $ | 212 |
| | $ | 203 |
| | $ | 212 |
| |
| Cash Paid During the Year: | | | | | | |
| Interest (net of $10, $12, and $12 capitalized, respectively) | | $ | 202 |
| | $ | 209 |
| | $ | 212 |
|
| Income taxes, net | 72 |
| | 215 |
| | 86 |
| 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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
| $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| | | | | | | | | | | |
| Other Paid-in Capital: | | | | | | | | | | |
| Beginning of year | 1,569 |
| | 1,560 |
| | 1,556 |
| 1,828 |
| | 1,822 |
| | 1,569 |
|
| Capital contribution from parent (Note 1) | 253 |
| | 224 |
| | 4 |
| |
| Return of capital to parent (Note 1) | — |
| | (215 | ) | | — |
| |
| Capital contribution from parent | | 30 |
| | 6 |
| | 253 |
|
| Other paid-in capital, end of year | 1,822 |
| | 1,569 |
| | 1,560 |
| 1,858 |
| | 1,828 |
| | 1,822 |
|
| | | | | | | | | | | |
| Preferred Stock | 80 |
| | 80 |
| | 80 |
| 80 |
| | 80 |
| | 80 |
|
| | | | | | | | | | | |
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 1,892 |
| | 1,842 |
| | 1,907 |
| 1,671 |
| | 1,669 |
| | 1,892 |
|
| Net income | 355 |
| | 393 |
| | 398 |
| 326 |
| | 360 |
| | 355 |
|
| Common stock dividends | (575 | ) | | (340 | ) | | (460 | ) | (362 | ) | | (355 | ) | | (575 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,669 |
| | 1,892 |
| | 1,842 |
| 1,632 |
| | 1,671 |
| | 1,669 |
|
| | | | | | | | | | | |
| Total Shareholders’ Equity | $ | 4,082 |
| | $ | 4,052 |
| | $ | 3,993 |
| $ | 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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Operating Revenues: | | | | | | | | | | |
| Electric | $ | 1,683 |
| | $ | 1,522 |
| | $ | 1,461 |
| $ | 1,784 |
| | $ | 1,736 |
| | $ | 1,683 |
|
| Gas | 783 |
| | 976 |
| | 847 |
| |
| Natural gas | | 743 |
| | 754 |
| | 783 |
|
| Other | — |
| | — |
| | 3 |
| 1 |
| | — |
| | — |
|
| Total operating revenues | 2,466 |
| | 2,498 |
| | 2,311 |
| 2,528 |
| | 2,490 |
| | 2,466 |
|
| Operating Expenses: | | | | | | | | | | |
| Purchased power | 420 |
| | 343 |
| | 380 |
| 417 |
| | 399 |
| | 420 |
|
| Gas purchased for resale | 358 |
| | 533 |
| | 448 |
| |
| Natural gas purchased for resale | | 264 |
| | 292 |
| | 358 |
|
| Other operations and maintenance | 797 |
| | 771 |
| | 693 |
| 789 |
| | 804 |
| | 797 |
|
| Depreciation and amortization | 295 |
| | 263 |
| | 243 |
| 341 |
| | 319 |
| | 295 |
|
| Taxes other than income taxes | 130 |
| | 138 |
| | 132 |
| 137 |
| | 132 |
| | 130 |
|
| Total operating expenses | 2,000 |
| | 2,048 |
| | 1,896 |
| 1,948 |
| | 1,946 |
| | 2,000 |
|
| Operating Income | 466 |
| | 450 |
| | 415 |
| 580 |
| | 544 |
| | 466 |
|
| Other Income and Expenses: | | | | | | | | | | |
| Miscellaneous income | 21 |
| | 17 |
| | 10 |
| 11 |
| | 21 |
| | 21 |
|
| Miscellaneous expense | 12 |
| | 8 |
| | 9 |
| 10 |
| | 12 |
| | 12 |
|
| Total other income | 9 |
| | 9 |
| | 1 |
| 1 |
| | 9 |
| | 9 |
|
| Interest Charges | 131 |
| | 112 |
| | 143 |
| 144 |
| | 140 |
| | 131 |
|
| Income Before Income Taxes | 344 |
| | 347 |
| | 273 |
| 437 |
| | 413 |
| | 344 |
|
| Income Taxes | 127 |
| | 143 |
| | 110 |
| 166 |
| | 158 |
| | 127 |
|
| Net Income | 217 |
| | 204 |
| | 163 |
| 271 |
| | 255 |
| | 217 |
|
| Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $(2), $(2), and $(2), respectively | (3 | ) | | (3 | ) | | (3 | ) | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $-, $(1), and $(2), respectively | | — |
| | (5 | ) | | (3 | ) |
| Comprehensive Income | $ | 214 |
| | $ | 201 |
| | $ | 160 |
| $ | 271 |
| | $ | 250 |
| | $ | 214 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
| Net Income | $ | 217 |
| | $ | 204 |
| | $ | 163 |
| $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
| 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 214 |
| | $ | 201 |
| | $ | 160 |
| $ | 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, |
| | 2015 | | 2014 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 71 |
| | $ | 1 |
| $ | — |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | 204 |
| | 212 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively) | | 234 |
| | 242 |
|
| Accounts receivable – affiliates | 22 |
| | 22 |
| 9 |
| | 10 |
|
| Unbilled revenue | 111 |
| | 119 |
| 158 |
| | 141 |
|
| Miscellaneous accounts receivable | 19 |
| | 9 |
| 35 |
| | 22 |
|
| Materials and supplies | 151 |
| | 177 |
| |
| Inventories | | 134 |
| | 135 |
|
| Current regulatory assets | 167 |
| | 129 |
| 87 |
| | 108 |
|
| Other current assets | 15 |
| | 15 |
| 15 |
| | 25 |
|
| Total current assets | 760 |
| | 684 |
| 672 |
| | 683 |
|
| Property and Plant, Net | 6,848 |
| | 6,165 |
| |
| Property, Plant, and Equipment, Net | | 8,293 |
| | 7,469 |
|
| Investments and Other Assets: | | | | | | |
| Goodwill | 411 |
| | 411 |
| 411 |
| | 411 |
|
| Regulatory assets | 771 |
| | 883 |
| 822 |
| | 816 |
|
| Other assets | 113 |
| | 61 |
| 147 |
| | 95 |
|
| Total investments and other assets | 1,295 |
| | 1,355 |
| 1,380 |
| | 1,322 |
|
| TOTAL ASSETS | $ | 8,903 |
| | $ | 8,204 |
| $ | 10,345 |
| | $ | 9,474 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 129 |
| | $ | — |
| $ | 457 |
| | $ | 250 |
|
| Short-term debt | — |
| | 32 |
| 62 |
| | 51 |
|
| Borrowings from money pool | — |
| | 15 |
| |
| Accounts and wages payable | 249 |
| | 207 |
| 337 |
| | 264 |
|
| Accounts payable – affiliates | 66 |
| | 50 |
| 70 |
| | 63 |
|
| Taxes accrued | 13 |
| | 17 |
| 19 |
| | 16 |
|
| Interest accrued | | 33 |
| | 33 |
|
| Customer deposits | 69 |
| | 77 |
| 69 |
| | 69 |
|
| Mark-to-market derivative liabilities | 45 |
| | 42 |
| |
| Current environmental remediation | 28 |
| | 52 |
| 42 |
| | 38 |
|
| Current regulatory liabilities | 39 |
| | 84 |
| 92 |
| | 78 |
|
| Other current liabilities | 114 |
| | 124 |
| 177 |
| | 109 |
|
| Total current liabilities | 752 |
| | 700 |
| 1,358 |
| | 971 |
|
| Long-term Debt, Net | 2,342 |
| | 2,224 |
| 2,373 |
| | 2,338 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 1,480 |
| | 1,248 |
| 1,021 |
| | 1,631 |
|
| Accumulated deferred investment tax credits | 2 |
| | 3 |
| 1 |
| | 2 |
|
| Regulatory liabilities | 732 |
| | 703 |
| 1,629 |
| | 768 |
|
| Pension and other postretirement benefits | 271 |
| | 277 |
| 285 |
| | 346 |
|
| Environmental remediation | 205 |
| | 199 |
| 134 |
| | 162 |
|
| Other deferred credits and liabilities | 222 |
| | 189 |
| 234 |
| | 222 |
|
| Total deferred credits and other liabilities | 2,912 |
| | 2,619 |
| 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 |
| | 1,980 |
| 2,013 |
| | 2,005 |
|
| Preferred stock | 62 |
| | 62 |
| 62 |
| | 62 |
|
| Retained earnings | 825 |
| | 611 |
| 1,235 |
| | 967 |
|
| Accumulated other comprehensive income | 5 |
| | 8 |
| |
| Total shareholders’ equity | 2,897 |
| | 2,661 |
| 3,310 |
| | 3,034 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 8,903 |
| | $ | 8,204 |
| $ | 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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | | | | | | |
| Net income | $ | 217 |
| | $ | 204 |
| | $ | 163 |
| $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | 292 |
| | 259 |
| | 238 |
| 341 |
| | 318 |
| | 292 |
|
| Amortization of debt issuance costs and premium/discounts | 14 |
| | 13 |
| | 15 |
| 13 |
| | 14 |
| | 14 |
|
| Deferred income taxes and investment tax credits, net | 221 |
| | 196 |
| | 104 |
| 171 |
| | 154 |
| | 221 |
|
| Other | (14 | ) | | (19 | ) | | 4 |
| — |
| | (1 | ) | | (14 | ) |
| Changes in assets and liabilities: | | | | | | | | | | |
| Receivables | 16 |
| | (13 | ) | | 50 |
| (7 | ) | | (72 | ) | | 16 |
|
| Materials and supplies | 25 |
| | (4 | ) | | 15 |
| |
| Inventories | | (1 | ) | | 15 |
| | 25 |
|
| Accounts and wages payable | 37 |
| | 7 |
| | 19 |
| 19 |
| | 12 |
| | 37 |
|
| Taxes accrued | (2 | ) | | (7 | ) | | 28 |
| 18 |
| | 1 |
| | (2 | ) |
| Regulatory assets and liabilities | (26 | ) | | (215 | ) | | (35 | ) | 16 |
| | 120 |
| | (26 | ) |
| Assets, other | 17 |
| | 15 |
| | 5 |
| (15 | ) | | (3 | ) | | 17 |
|
| Liabilities, other | (27 | ) | | 1 |
| | 10 |
| 3 |
| | (5 | ) | | (27 | ) |
| Pension and other postretirement benefits | (4 | ) | | (6 | ) | | (8 | ) | (14 | ) | | (8 | ) | | (4 | ) |
| Counterparty collateral, net | (3 | ) | | 14 |
| | 43 |
| — |
| | 3 |
| | (3 | ) |
| Net cash provided by operating activities | 763 |
| | 445 |
| | 651 |
| 815 |
| | 803 |
| | 763 |
|
| Cash Flows From Investing Activities: | | | | | | | | | | |
| Capital expenditures | (918 | ) | | (835 | ) | | (701 | ) | (1,076 | ) | | (924 | ) | | (918 | ) |
| Other | 5 |
| | 7 |
| | 6 |
| 6 |
| | 6 |
| | 5 |
|
| Net cash used in investing activities | (913 | ) | | (828 | ) | | (695 | ) | (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 | (32 | ) | | 32 |
| | — |
| 11 |
| | 51 |
| | (32 | ) |
| Money pool borrowings, net | (15 | ) | | (41 | ) | | 32 |
| — |
| | — |
| | (15 | ) |
| Redemptions, repurchases, and maturities of long-term debt | — |
| | (163 | ) | | (150 | ) | (250 | ) | | (129 | ) | | — |
|
| Issuances of long-term debt | 248 |
| | 548 |
| | 278 |
| 496 |
| | 240 |
| | 248 |
|
| Capital issuance costs | (3 | ) | | (6 | ) | | (2 | ) | (6 | ) | | (4 | ) | | (3 | ) |
| Capital contribution from parent | 25 |
| | 15 |
| | — |
| 8 |
| | — |
| | 25 |
|
| Other | — |
| | 1 |
| | — |
| (1 | ) | | (1 | ) | | — |
|
| Net cash provided by financing activities | 220 |
| | 383 |
| | 45 |
| 255 |
| | 44 |
| | 220 |
|
| Net change in cash and cash equivalents | 70 |
| | — |
| | 1 |
| — |
| | (71 | ) | | 70 |
|
| Cash and cash equivalents at beginning of year | 1 |
| | 1 |
| | — |
| — |
| | 71 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | 71 |
| | $ | 1 |
| | $ | 1 |
| $ | — |
| | $ | — |
| | $ | 71 |
|
| | | | | | | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | | | | | | |
| Interest (net of $5, $2, and $4 capitalized, respectively) | $ | 120 |
| | $ | 110 |
| | $ | 112 |
| |
| Interest (net of $4, $3, and $5 capitalized, respectively) | | $ | 139 |
| | $ | 127 |
| | $ | 120 |
|
| Income taxes, net | (113 | ) | | (44 | ) | | (23 | ) | (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, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | |
| Other Paid-in Capital |
| |
| |
|
| |
| |
|
| Beginning of year | 1,980 |
| | 1,965 |
| | 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 |
| | 1,980 |
| | 1,965 |
| 2,013 |
| | 2,005 |
| | 2,005 |
|
| | | | | | | | | | | |
| Preferred Stock | 62 |
| | 62 |
| | 62 |
| 62 |
| | 62 |
| | 62 |
|
| | | | | | | | | | | |
| Retained Earnings: | | | | | | | | | | |
| Beginning of year | 611 |
| | 410 |
| | 360 |
| 967 |
| | 825 |
| | 611 |
|
| Net income | 217 |
| | 204 |
| | 163 |
| 271 |
| | 255 |
| | 217 |
|
| Common stock dividends | — |
| | — |
| | (110 | ) | — |
| | (110 | ) | | — |
|
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 825 |
| | 611 |
| | 410 |
| 1,235 |
| | 967 |
| | 825 |
|
| | | | | | | | | | | |
| Accumulated Other Comprehensive Income: | | | | | | | | | | |
| Deferred retirement benefit costs, beginning of year | 8 |
| | 11 |
| | 14 |
| — |
| | 5 |
| | 8 |
|
| Change in deferred retirement benefit costs | (3 | ) | | (3 | ) | | (3 | ) | — |
| | (5 | ) | | (3 | ) |
| Deferred retirement benefit costs, end of year | 5 |
| | 8 |
| | 11 |
| — |
| | — |
| | 5 |
|
| Total accumulated other comprehensive income, end of year | 5 |
| | 8 |
| | 11 |
| — |
| | — |
| | 5 |
|
| | | | | | | | | | | |
| Total Shareholders’ Equity | $ | 2,897 |
| | $ | 2,661 |
| | $ | 2,448 |
| $ | 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, 20152017
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 and Ameren Illinois. 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 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 transmission and 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 transmission and distribution businesses in Illinois. Ameren Illinois was created by the merger of CILCO and IP with and into CIPS in 2010. CIPS was incorporated in Illinois in 1923 and wasis 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 having 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.
Ameren has various other subsidiaries that conduct activities such as the provision of shared services. Ameren also has a subsidiary, ATXI that 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. Ameren is also pursuing projects, to improve electric transmission system reliability within Ameren Missouri's and Ameren Illinois'placed the Spoon River project in service territories as well as competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO.in February 2018.
In December 2013, Ameren completed the divestiture of
New AER to IPH. In January 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. In addition, in 2013, Ameren abandoned the Meredosia and Hutsonville energy centers upon the completion of the divestiture of New AER to IPH. Ameren is demolishing the Hutsonville energy center and expects to demolish the Meredosia energy center beginning in 2016. As a result of these events, Ameren has segregated New AER’s and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise stated, these notes to the financial statements exclude discontinued operations for all periods presented. See Note 16 – Divestiture Transactions and Discontinued Operations for additional information regarding these transactions.
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 and therefore their financial statements are not prepared on a consolidated basis. All intercompany transactions have been eliminated.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'Illinois participates in performance-based formula ratemaking frameworks established pursuant to the IEIMA and the FEJA for its electric distribution business participates in the performance-based formula ratemaking process established
pursuant to the IEIMA.and its electric energy-efficiency investments. Ameren Illinois also has an environmental cost rider,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. At December 31, 2017 and 2016, the trust fund balance of $23 million and $22 million, respectively, was reflected in “Other assets” on Ameren’s and Ameren Illinois’ balance 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.
Materials and SuppliesInventories
Materials and suppliesInventories are recorded at the lower of weighted-average cost or market. Cost is determined by the average-cost method. Materials and suppliesnet realizable value. Inventories are capitalized as inventory 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 materials and suppliesinventories for each of the Ameren Companies at December 31, 20152017 and 20142016:
|
| | | | | | | | | | | | |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2015 | | | | | | |
Fuel(a) | | $ | 173 |
| | $ | — |
| | $ | 173 |
|
| Gas stored underground | | 10 |
| | 87 |
| | 97 |
|
| Other materials and supplies | | 204 |
| | 64 |
| | 268 |
|
| Total materials and supplies | | $ | 387 |
| | $ | 151 |
| | $ | 538 |
|
| 2014 | | | | | | |
Fuel(a) | | $ | 134 |
| | $ | — |
| | $ | 134 |
|
| Gas stored underground | | 16 |
| | 111 |
| | 127 |
|
| Other materials and supplies | | 197 |
| | 66 |
| | 263 |
|
| Total materials and supplies | | $ | 347 |
| | $ | 177 |
| | $ | 524 |
|
|
| | | | | | | | | | | | |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2017 | | | | | | |
Fuel(a) | | $ | 154 |
| | $ | — |
| | $ | 154 |
|
| Natural gas stored underground | | 8 |
| | 74 |
| | 82 |
|
| Materials, supplies, and other | | 226 |
| | 60 |
| | 286 |
|
| Total inventories | | $ | 388 |
| | $ | 134 |
| | $ | 522 |
|
| 2016 | | | | | | |
Fuel(a) | | $ | 172 |
| | $ | — |
| | $ | 172 |
|
| Natural gas stored underground | | 9 |
| | 73 |
| | 82 |
|
| Materials, supplies, and other | | 211 |
| | 62 |
| | 273 |
|
| Total inventories | | $ | 392 |
| | $ | 135 |
| | $ | 527 |
|
| |
| (a) | Consists of coal, oil, and propane. |
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, 2015 and 2014, related to the rate-adjustment mechanisms discussed below.
In Ameren Missouri’s and Ameren Illinois’ natural gas utility jurisdictions, changes in natural gas costs are reflected in billings to their natural gas utility 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 natural gas utility customers in a subsequent period.
In Ameren Illinois’ retail electric utility jurisdiction, changes in purchased power and transmission service costs are reflected in billings to its electric utility 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 electric utility 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 utility customers in a subsequent period. As of 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 Plant,Equipment, Net
We capitalize the cost of additions to, and betterments of, units of property, plant, and plant.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 Plant,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 2015, 2014,2017, 2016, and 20132015 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 2015, 2014,2017, 2016, and 2013:2015:
| | | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Ameren Missouri | 7 | % | | 7 | % | | 8 | % | 7 | % | | 7 | % | | 7 | % |
| Ameren Illinois | 6 | % | | 2 | % | | 8 | % | 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' carrying amountIllinois had goodwill of goodwill was $411 million at December 31, 2015,2017 and 2014. All of Ameren's2016. Ameren has four reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois'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, 20152017 and 2014, was assigned to2016. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit.unit at December 31, 2017 and 2016.
WeAmeren 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 the Ameren Illinoistheir reporting unitunits below itstheir carrying amount. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment before calculatingamounts. To determine whether the fair value of the reporting unit. If an entity determines, on the basis of qualitative factors, that the fair value of thea reporting unit is more likely than not less than the carrying amount, a two-step quantitative test is required. An entity has the option to bypass the qualitative assessment in any period and proceed directly to
the first step of the quantitative test, which compares the fair value of the reporting unit to its carrying amount. If the carrying amount of the reporting unit exceeds its estimated fair value, the entity performs the second step, which requires an assignment of the reporting unit's fair value to the individual assets and liabilities in order to determine the implied fair value of the reporting unit's goodwill. If the implied fair value of goodwill is lessgreater than its carrying amount, an impairment loss is recorded.
Ameren and Ameren Illinois electedelect to perform either a qualitative assessment or to bypass the qualitative assessment and completed the first step of theperform a quantitative test, as of Octoberon an annual basis. On December 31, 2015. Based on the results,2016, due to a change in reporting units, Ameren and Ameren Illinois performed a quantitative test and determined that the estimated fair value of theeach 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, 2017.
The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was more likely than not that the fair value of each reporting unit significantly exceeded its carrying value as of October 31, 2015, indicating2017, resulting in no impairment of Ameren’s or Ameren Illinois’ goodwill. Ameren'sThe following factors, among others, were considered by Ameren and Ameren Illinois' valuation approach is based on a market participant view. It uses a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in estimatingIllinois when they assessed whether it was more likely than not that the fair value of each of their reporting units exceeded its carrying value as of October 31, 2017:
macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
pending regulatory rate review outcomes and projections of future regulatory rate review outcomes;
changes in laws and potential law changes;
observable industry market multiples;
achievement of IEIMA and FEJA performance metrics and the Ameren Illinois reporting unit include discountyield of 30-year United States Treasury bonds;
an unexpected further reduction in the FERC-allowed return on equity with respect to transmission services; and growth rates, utility sector market performance and transactions, and
projected operating results and cash flows.
The goodwill assigned to the Ameren Illinois reporting unit on the December 31, 2015 balance sheets of Ameren and Ameren Illinois had no accumulated goodwill impairment losses. Ameren and Ameren Illinois will continue to monitor internal and external factors for signs of possible declines in estimated fair value and potential goodwill impairment.
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 20152017 and 2014.2016.
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 are required to 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 to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments toadjust AROs based on changes in the estimated fair values of the obligations. Corresponding increasesobligations with a corresponding increase or decrease in the asset book value. Asset book values, reflected within “Property, Plant, and Equipment, Net” on the balance sheet, are depreciated over the remaining useful life of the related asset. Due to regulatory recovery, that depreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $26 million, $31 million, and $13 million for the years ended December 31, 2017, 2016, and 2015, respectively, which was deferred as a reduction to 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 as a regulatory liability. Uncertainties as to the probability, timing, or amount of cash expenditures associated with AROs affect our estimates of fair value. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with Ameren Missouri’s Callaway energy center decommissioning, costs, 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. Ameren and Ameren Missouri have a nuclear decommissioning trust fund for the decommissioning of the Callaway energy center. Asset removal costs accrued by our rate-regulated operations 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, 20152017 and 2014:2016:
| | | | Ameren Missouri | | Ameren Illinois | | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren | |
| Balance at December 31, 2013 | $ | 366 |
| | $ | 3 |
| | $ | 369 |
| | |
| Balance at December 31, 2015 | | $ | 617 |
| | $ | 6 |
| | $ | 623 |
| |
| Liabilities incurred | 2 |
| | — |
| | 2 |
| | 3 |
| | — |
| | 3 |
| |
| Liabilities settled | (2 | ) | | (a) |
| | (2 | ) | | (2 | ) | | (a) |
| | (2 | ) | |
Accretion in 2014(b) | 21 |
| | (a) |
| | 21 |
| | |
Accretion in 2016(b) | | 25 |
| | (a) |
| | 25 |
| |
Change in estimates(c) | 2 |
| | 4 |
| | 6 |
| | 1 |
| | — |
| | 1 |
| |
| Balance at December 31, 2014 | $ | 389 |
| | $ | 7 |
| (d) | $ | 396 |
| | |
| Balance at December 31, 2016 | | $ | 644 |
| (c) | $ | 6 |
| (d) | $ | 650 |
| (c) |
| Liabilities incurred | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| |
| Liabilities settled | (1 | ) | | (1 | ) | | (2 | ) | | (12 | ) | | (1 | ) | | (13 | ) | |
Accretion in 2015(b) | 23 |
| | (a) |
| | 23 |
| | |
Accretion in 2017(b) | | 26 |
| | (a) |
| | 26 |
| |
Change in estimates(e) | 203 |
| | (a) |
| | 203 |
| | (18 | ) | | (1 | ) | | (19 | ) | |
| Balance at December 31, 2015 | $ | 617 |
| (f) | $ | 6 |
| (d) | $ | 623 |
| (f) | |
| Balance at December 31, 2017 | | $ | 640 |
| (c) | $ | 4 |
| (d) | $ | 644 |
| (c) |
| |
| (b) | AccretionAmeren Missouri’s accretion expense was recordeddeferred as an increasea decrease to regulatory assets at Ameren Missouri and Ameren Illinois.liabilities. |
| |
| (c) | The ARO increase resultedBalance included $6 million and $15 million in a corresponding increase recorded to "Property“Other current liabilities” on the balance sheet as of December 31, 2017 and Plant, Net." Ameren Illinois changed its fair value estimate for asbestos removal.2016, respectively. |
| |
| (d) | Included in “Other deferred credits and liabilities” on the balance sheet. |
| |
| (e) | The ARO increase resulted in a corresponding increase recorded to "Property and Plant, Net." Ameren and Ameren Missouri increased their AROs relatedchanged 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 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,in 2017, and a reductionan increase in the assumed 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. |
| |
(f) | Balance included $5 million in "Other current liabilities" on the balance sheet as of December 31, 2015.rate. |
See Note 16 – Divestiture Transactions and Discontinued Operations 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, 20152017 and 2014,2016, 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 delivery 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 deliverydistribution 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 the next 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 the next 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 and recognize revenuesestimated. Revenues are recognized once the resettlement amount is received. There were no material MISO resettlements in 2017, 2016, or 2015.
Nuclear Fuel
Ameren Missouri’s cost of nuclear fuel is capitalized and then amortized to fuel expense on a unit-of-production basis. The cost is charged to "Operating“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 – Gas,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 – Gas,Natural gas,” and “Operating Expenses – Taxes other than income taxes” for the years ended December 31, 2015, 2014,2017, 2016, and 2013:2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 153 |
| | $ | 151 |
| | $ | 156 |
|
| Ameren Illinois | 57 |
| | 57 |
| | 57 |
|
| Ameren | $ | 210 |
| | $ | 208 |
| | $ | 213 |
|
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Ameren Missouri | $ | 156 |
| | $ | 151 |
| | $ | 152 |
|
| Ameren Illinois | 57 |
| | 64 |
| | 61 |
|
| Ameren | $ | 213 |
| | $ | 215 |
| | $ | 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 facilityagreement fees are amortized over the credit facility term.term of the agreement.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance.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 changes.
Investmentincreases. 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.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“Net Income Attributable to Ameren common shareholdersCommon Shareholders” by the weighted-average number of common shares outstanding during the period. Earnings per diluted share is computed by dividing net income attributable“Net Income Attributable to Ameren common shareholdersCommon 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 1.01.6 million, 1.80.8 million, and 1.91.0 million for the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, respectively. There were no potentially dilutive securities excluded from the diluted earnings per share calculations for the years ended December 31, 2015, 2014,2017, 2016, and 2013.2015.
Capital ContributionsDivestiture Transactions and Return of CapitalDiscontinued Operations
In 2015,December 2013 and January 2014, Ameren Missouricompleted the divestiture of New AER and Ameren Illinois received cash capital contributions of $224 million and $25 million, respectively, from Ameren (parent) as a result of the tax allocation agreement. Additionally, as of December 31, 2015, Ameren Missouri accrued a $38 million capital contributioncertain other assets. All matters related to the same agreement.
In 2014,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 Missouriremoved a reserve for unrecognized tax benefits of $53 million recorded in 2013 and recognized a tax benefit from discontinued operations. Ameren Illinois received cash capital contributions of $215also paid $25 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).
Supplemental Cash Flow Information
The following table presents additional information regarding Ameren's consolidated statement of cash flows for the years ended December 31, 2015, 2014, and 2013:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Cash paid (refunded) during the year: |
| Interest | | | | | |
Continuing operations(a) | $ | 335 |
| | $ | 333 |
| | $ | 362 |
|
Discontinued operations(b) | — |
| | — |
| | 31 |
|
| | $ | 335 |
| | $ | 333 |
| | $ | 393 |
|
| | | | | | |
| Income taxes, net | | | | | |
| Continuing Operations | $ | (17 | ) | | $ | (41 | ) | | $ | 116 |
|
| Discontinued Operations | 2 |
| | 14 |
| | (108 | ) |
| | $ | (15 | ) | | $ | (27 | ) | | $ | 8 |
|
| |
(a) | Net of $17 million, $18 million, and $20 million capitalized, respectively. |
| |
(b) | Net of $- million, $- million, and $17 million capitalized, respectively. |
See Note 3 – Property and Plant, Net, for information on accrued capital expenditures.concluded its obligations with New AER.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance, as well as guidance issued but not yet adopted, that could affect the Ameren Companies.
Revenue from Contracts with Customers
In May 2014, the FASB issued authoritative accounting 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 full retrospective method), or retrospectively by recordingthey can record a cumulative effect adjustment to retained earnings in the period of initial adoption. The Ameren Companies are currently assessingadoption (the modified retrospective method).
We have completed the impactsevaluation of our contracts. Adoption of this guidance on their resultswill not result in material changes to the amount or timing of operations,revenue recognition. We will apply the guidance using the full retrospective method. We will include disaggregated revenue disclosures by segment and customer class in the combined notes to the financial position, and disclosures, including their accountingstatements. This guidance will be effective for contributions in aid of construction and similar arrangements, as well as the transition method that they will use to adopt the guidance. In August 2015, the FASB deferred the effective date of this revenue guidance toAmeren Companies for the first quarter of 2018, with an option for entities to early adopt in2018.
Improving the first quarterPresentation of 2017. The Ameren Companies do not expect to early adopt this guidance.
Amendments to the Consolidation AnalysisNet Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In February 2015,March 2017, the FASB issued authoritative accounting 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 newoutside of operating income. Our adoption of this guidance affects (1) limited partnershipswill result in the reclassification of 2017 net benefit income of $44 million, $22 million, and similar legal entities, (2) evaluating fees paid to a decision maker or service provider$10 million, currently presented as a variable interest, (3) the effectreduction of fee arrangements"Other operations and maintenance expense," on the primary beneficiary determination, (4) the effectAmeren's, Ameren Missouri's, and Ameren Illinois' respective statements of related partiesincome. 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 the primary beneficiary determination,Ameren's, Ameren Missouri's, and (5) certain investment funds. Ameren Illinois' respective statements of income, will also be reclassified and presented outside of operating income.
The guidance also permits an entity to capitalize only the service cost component as part of an asset, such as inventory or property, plant, and equipment, on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization. This change in the capitalization of net benefit costs is not expected to affect our ability to recover total net benefit cost through customer rates. This guidance will be effective for the Ameren Companies in the first quarter of 2018. See Note 10 – Retirement Benefits for the components of net benefit cost.
Restricted Cash
In November 2016, the FASB issued authoritative guidance that requires restricted cash and canrestricted 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 reporting period presentedpresented.
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 by recordingwith a cumulative effect adjustment to retained earnings inas of the periodadoption 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 initial adoption.credit losses expected to be incurred over the life of the financial instruments. The Ameren Companiesguidance 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 and do not expect any material impacts to theiron our results of operations, financial position, or cash flows.
Presentation of Debt Issuance Costs
In April 2015,and disclosures. The credit loss guidance will be effective for the FASB issued authoritative accounting guidance to simplify the presentation of debt issuance costsAmeren Companies in the balance sheet. The guidancefirst quarter of 2020. It requires debt issuance costschanges to be presentedapplied retrospectively with a cumulative effect adjustment to retained earnings as a reduction toof the associated debt liability. Previously, debt issuance costs were presented in "Other assets" on the Ameren Companies' balance sheets. The Ameren Companies early adopted this standard in 2015 and applied the guidance retrospectively. At December 31, 2015, debt issuance costs of $43 million, $19 million, and $18 million were presented in "Long-term debt, net" on Ameren's, Ameren Missouri's, and Ameren Illinois' balance sheets, respectively. At December 31, 2014, debt issuance costs of $35 million, $18 million, and $17 million previously presented in "Other assets" on Ameren's, Ameren Missouri's, and Ameren Illinois' respective balance sheets were reclassified to Long-term debt, net" for comparative purposes. See Note 5 – Long-Term Debt and Equity Financings for additional information. The implementation of this authoritative accounting guidance did not affect the Ameren Companies' results of operations or cash flows.
Balance Sheet Classification of Deferred Income Taxes
In November 2015, the FASB issued authoritative accounting guidance to simplify the presentation of deferred income taxes in the balance sheet. The guidance requires all deferred tax assets and liabilities, along with any related valuation allowances, to be classified as noncurrent on the balance sheet. Previously, the current portion of deferred taxes was presented as "Current accumulated deferred income taxes, net" and the noncurrent portion of deferred taxes was presented as "Accumulated deferred income taxes, net" on the Ameren Companies' balance sheets. The Ameren Companies early adopted this standard in 2015 and applied the guidance retrospectively. At December 31, 2014, the current deferred income taxes of $352 million, $49 million, and $160 million, which were previously presented as "Current accumulated deferred income taxes, net" on Ameren's, Ameren Missouri's, and Ameren Illinois' respective balance sheets, were reclassified and presented in "Accumulated deferred income taxes, net" for comparative purposes. The implementation of this authoritative accounting guidance did not affect the Ameren Companies' results of operations or cash flows.adoption date.
Leases
In February 2016, the FASB issued authoritative accounting guidance that will requirerequires an entity to recognize assets and liabilities arising from all leases with a lease.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 primarily 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. TheThis 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 2019,2019. See Note 14 – Commitments and includes an optionContingencies for entities to early adopt. Theadditional information on our leases.
Reclassification of Certain Tax Effects from Accumulated OCI
In February 2018, the FASB issued authoritative guidance requiresallowing a retrospective cumulative adjustmentreclassification 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 initial adoption. The Ameren CompaniesWe are currently assessing whether we will elect to perform such a reclassification and the impacts of this guidance on their results of operations, financial position, cash flows and disclosures.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 the final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.
Missouri
2015March 2017 Electric Rate Order
In April 2015,March 2017, the MoPSC issued an order approving a $122unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which was a $92 million increase in Ameren Missouri’s annual revenuesrevenue requirement for electric service, including $109 million related to the increase in net energy costs above those included in base rates previously authorized by the MoPSC. The revenue increase was based on a 9.53% return on common equity, a capital structure composed of 51.8% common equity, and a rate base of $7.0 billion to reflect
investments through December 31, 2014. Rate changes consistentcompared with the orderprior revenue requirement established in the MoPSC’s April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on May 30, 2015.April 1, 2017.
The order approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude all transmission revenues and substantially all transmission charges. The order did not approveauthorized the continued use of the regulatory tracking mechanisms for storm costs or for vegetation managementFAC and infrastructure inspection costs. These changes to Ameren Missouri’s recovery mechanisms are expected to contribute to regulatory lag. The order did approve the continued use of the regulatory tracking mechanisms for pension and other postretirement benefits, uncertain income tax positions, and renewable energy standard costs, solar rebates, and uncertain tax positionsstandards that the MoPSC authorized in priorearlier electric rate orders.
In addition, the order approved These regulatory tracking mechanisms provide for a reductionbase level of expense to Noranda’sbe reflected in Ameren Missouri’s base electric rates with differences between the base amount and the actual expenses incurred deferred as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decreased by $54 million from the base level established in the MoPSC’s April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC’s April 2015 electric rate order.
MEEIA
In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a stipulation and agreement among Ameren Missouri, the MoPSC staff, and the MoOPC. Ameren Missouri will collect the performance incentive over a two-year period that began in February 2017.
In November 2015, the MoPSC issued an offsetting increase in electric rates for Ameren Missouri’s other customers. The rate shift is designedorder regarding the determination of a certain input used to be revenue neutral for Ameren Missouri. In June 2015,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, concerningupheld the reduction to Noranda’s electric rates included in the MoPSC’sNovember 2015 MoPSC order. In February 2016, Ameren Missouri withdrew its appeal.
then appealed that decision to the Missouri Supreme Court. If the decision is overturned, Ameren Missouri would recognize an additional $9 million MEEIA 2013 performance incentive.
The MEEIA established a regulatory framework that, among other things, requires the MoPSC to ensure that a utility’s financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy efficiency programs. Missouri does not have a law mandating energy efficiency programs.
In August 2012, the MoPSC approved Ameren Missouri’s customer energy efficiency programs, net shared benefits, and performance incentive for 2013 through 2015. From 2013 through 2015,2016 program provided Ameren Missouri invested $134 million in customer energy efficiency programs and realized $174 million of net shared benefits. The MoPSC also establishedwith a performance incentive that would provide Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy efficiencyenergy-efficiency goals, including $19$27 million if 100% of the goals were achieved during the three-year period, with the potential to earn a larger performance incentivemore if Ameren Missouri’s energy savings exceeded those goals.
In June 2015,September 2017, Ameren Missouri received an order from the MoPSC staff filed a complaint case with the MoPSC regarding the method and inputs used in calculating the performance incentive for 2014 and 2015. In November 2015, the MoPSC issued an order that adopted the MoPSC staff’s method and inputs used in calculating the performance incentive for 2014 and 2015. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District. If the Missouri Court of Appeals upholds the MoPSC order, the performance incentive awarded from the 2014 and 2015 MEEIA programs will be significantly less than the performance incentive calculated usingapproving Ameren Missouri’s interpretation. Ameren Missouri has not recorded revenues associated withenergy savings results for the
performance incentive for any first year of the MEEIA program years.2016 programs. As a result of this order and in accordance with revenue recognition guidance, Ameren Missouri believes that it will ultimately be foundrecognize $5 million of additional revenues in the first quarter of 2018 relating to have exceeded 100% of the customer energy efficiency goals, and it therefore expects to recognize revenues of at least $19 million in 2016.MEEIA 2016 performance incentive.
MoPSC Federal Income Tax Proceeding
In February 2016,2018, the MoPSC issued an order approving Ameren Missouri's March 2016initiated proceedings to February 2019 MEEIA plan which included a portfolioinvestigate how the effect of customer energy efficiency programs along with a rider to collect the program costs,reduction in the throughput disincentive, and a performance incentive from customers. The throughput disincentive recovery will replace the net shared benefits that were collectedfederal statutory corporate income tax rate enacted under the 2013 through 2015 MEEIA plan. The MEEIA rider will allowTCJA 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 collectpredict the throughput disincentive without a traditional rate proceeding, until such time as lower volumes resultingtiming or the magnitude of any impact on its electric and natural gas rates that may result from the MEEIA programs are reflectedultimate resolution of this matter.
ATXI’s Mark Twain Project
The Mark Twain project is a MISO-approved transmission line to be located in base rates. Customer rates will be based upon both forecasted program costsnortheast Missouri with an expected investment of $250 million. In the third quarter of 2017, ATXI finalized an alternative project route and throughput disincentive which will be annually reconciled to actual results. Beginning in March 2016,reached agreements with Ameren Missouri intendsand an electric cooperative in northeast Missouri to invest $158 million over the three-year period in customer energy efficiency programs. In addition, similar to the MEEIA plan that ended in December 2015, the MoPSC's order approved a performance incentive that would provide Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy efficiency goals, including $27 million if 100%locate almost all of the goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 25% of its energy efficiency goals before it earns a performance incentive.
Noranda
Ameren Missouri supplies electricity to Noranda’s aluminum smelter located in southeast Missouri under a long-term power supply agreement. In May 2015, Ameren Missouri notified Noranda of its intent to terminate the agreement effective June 1, 2020. If Ameren Missouri wants to cease providing electricity to Noranda following the termination date, Ameren Missouri wouldMark Twain project on existing line corridors. It also be required to obtain approvalreceived assents for road crossings from the MoPSC.
Onfive affected counties in northeast Missouri. In January 8, 2016, Noranda announced that production had been idled at two of its three pot lines at the smelter following an electric supply circuit failure on assets not owned by Ameren Missouri. On January 13, 2016, Noranda announced that the smelter’s “remaining operations will be curtailed on or before March 12, 2016, unless [Noranda] is able to secure a substantially more sustainable power rate for the smelter and materially improve [Noranda’s] overall liquidity.” Ameren Missouri has been working with Noranda, legislators and other stakeholders on a potential legislative solution to support Noranda’s operations.
In its April 2015 electric rate order, the MoPSC approved a rate design that established $78 million in annual revenues, net of fuel and purchased power costs, as Noranda’s portion of Ameren Missouri’s revenue requirement. The portion of Ameren Missouri’s annual revenue requirement reflected in Noranda’s electric rate is based on the smelter using approximately 4.2
million megawatthours annually, which is almost 100% of its operating capacity. Ameren Missouri’s rates, including those for Noranda, are seasonal. Noranda’s summer base rate (June through September) is $45.78 per megawatthour and its winter base rate (October through May) is $31.11 per megawatthour.
In 2016, actual sales volumes to Noranda will be significantly below the sales volumes reflected in rates. As a result, Ameren Missouri will not fully recover its revenue requirement until rates are adjusted by the MoPSC in a future electric rate case to accurately reflect Noranda’s actual sales volumes. In light of the Noranda announcements described above, Ameren Missouri expects to employ a provision in its FAC tariff that, under certain circumstances, allows Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced tariff sales to Noranda. The current market price of electricity is less than Noranda’s electric rate, and Ameren Missouri expects market prices to remain below Noranda’s electric rate during 2016. Accordingly, this FAC provision would not enable Ameren Missouri to fully recover its revenue requirement under current market conditions.
Although Ameren Missouri has not decided when to file its next electric rate case, on January 11, 2016, Ameren Missouri filed a notice with the MoPSC, that would enable Ameren Missouri to file a rate case after 60 days. Ameren Missouri expects to file a rate case in 2016 and expects the resulting new rates to reflect Noranda’s actual sales volumes which would prospectively eliminate the impact of the current revenue shortfall. The rate case would take place over a period of up to 11 months from the date of filing. Ameren Missouri may seek recovery of lost revenues in a filing with the MoPSC for certain costs incurred but not contemporaneously recovered as a result of Noranda's reduced operations. Ameren Missouri will continue to monitor Noranda’s sales volumes and to evaluate regulatory and legislative options that might mitigate adverse financial impacts. The reduction in Noranda’s sales volumes will adversely affect Ameren’s and Ameren Missouri’s results of operations, financial condition, and liquidity until customer rates are adjusted in a future rate case.
On February 8, 2016, Noranda filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In the filing, Noranda reaffirmed that the remaining pot line will continue to operate at the smelter until March 2016, at which time operation of the line will be curtailed. Noranda stated it would maintain the flexibility to restart operations at the smelter should conditions allow. For utility service through February 8, 2016, Noranda had prepaid an amount to Ameren Missouri in excess of its utility service usage. Ameren Missouri expects to be paid in full for utility services provided after February 8, 2016.
ATXI Transmission Projects
In May 2015,2018, the MoPSC granted ATXI a certificate of convenience and necessity for the seven-mile portion of the Illinois Rivers project located in Missouri.
In June 2015, ATXI made a filing with the MoPSC requesting a certificate of convenience and necessity for the Mark Twain project. The Mark TwainATXI plans to begin construction in the second quarter of 2018 and to complete the project is a MISO-approved 100-mile transmission line located in northeast Missouri. A decision is expected fromby the MoPSC in 2016.end of 2019.
Illinois
IEIMA & FEJA
Under the provisions of the IEIMA's performance-baseda formula rate-makingratemaking framework which currently extendseffective through 2019,2022, Ameren Illinois’ electric deliverydistribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs. Throughout eachcosts 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, 2015,2017, Ameren Illinois had recorded regulatory assets of $62$54 million and $103$24 million, including interest, to reflect its expected 20152017 and the 2014its approved 2016 revenue requirement reconciliation adjustments, respectively. As of December 31, 2014,2016, Ameren Illinois had recorded a $65$68 million regulatory asset to reflect its approved 20132015 revenue requirement reconciliation adjustment, which was collected, with interest, from customers during 2015.2017.
In December 2015,2017, the ICC issued an order in Ameren Illinois’ annual update filing approvingthat approved a $106$17 million increasedecrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2016.2018. This update reflectsreflected an increase to the annual formula rate based on 20142016 actual recoverable costs and expected net plant additions for 2015,2017, as well as an increase to include the 20142016 revenue requirement reconciliation adjustment, which was recorded as a regulatory asset at December 31, 2015, andadjustment. The increases in the update filing were more than offset by a decrease for the conclusion of the 20132015 revenue requirement reconciliation adjustment, which was fully collected from customers in 2015.2017, 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 framework through 2022, and clarifying that a common equity ratio up to and including 50% is prudent. Beginning in 2017, the FEJA permitted Ameren Illinois to recover, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenue during the third quarter and less revenue during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed the method it uses to recognize interim-period revenue. Ameren Illinois now recognizes revenue consistent with the timing of actual incurred electric distribution recoverable costs, and it recognizes revenue associated with the expected return on its rate base ratably over the year. The decoupling provisions of the FEJA do not expire at the end of 2022.
The FEJA allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the company’s weighted-average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. The FEJA increased the level of electric energy-efficiency saving targets through 2030. In December 2013,June 2017, pursuant to the FEJA, Ameren Illinois filed 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 $99 million per year in electric energy-efficiency programs from 2018 through 2021. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that disallowed, in part,exceed amounts allowed by legislation. The electric energy-efficiency program investments and the recoveryreturn on those investments will be collected from customers through a rider; 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 debt premium costs paid byincrease 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 a tender offer in August 2012 to repurchase outstanding senior secured notes. As a resultthe net amount of the ICCdifference 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 2013, Ameren andeffect. In February 2018, Ameren Illinois each recordedfiled a pretax charge to earnings of $15 million relatingresponse to the partial disallowanceICC seeking approval of a rider that calculates such differences, specifically by evaluating the debt premium costs. In December 2014,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, issued an order that allowed partial recovery from customers of the previously disallowed debt premium costs. Accordingly,over a one-year period beginning in 2014, Ameren and Ameren Illinois each recorded a pretax increase to earnings of $11 million to reflect the partial recovery
May 2018.of the debt premium costs. Ameren and Ameren Illinois recorded the effects of the 2013 and 2014 orders to "Interest charges" with a corresponding offset to "Regulatory assets."
20152018 Natural Gas Delivery Service Regulatory Rate OrderReview
In December 2015,January 2018, Ameren Illinois filed a request with the ICC issued a rate order that approved anseeking approval to increase inits annual revenues for Ameren Illinois' natural gas delivery service by $49 million, which included an estimated $42 million of $45 million. annual revenues that would otherwise be recovered under a QIP rider. The revenue increaserequest was based on a 9.6%10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.2$1.6 billion. The request reflects the reduction in the federal corporate income tax rate order was based onas a 2016result 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. Theyear 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 were in effect in January 2016. In addition, the rate order approved the VBA for residential and small nonresidential customers beginning in 2016.
2015 ICC Purchased Power Reconciliation
In January 2015, the ICC issued an ordermay approve, nor whether any rate changes that may eventually be approved Ameren Illinois' reconciliation of revenues collected under its purchased power rider mechanism and Ameren Illinois' related cumulative power usage cost. In the first quarter of 2015, based on the January 2015 order, both Ameren and Ameren Illinois recorded a $15 million increasewill be sufficient to electric revenues for the recovery of this cumulative power usage cost from electric customers.
ATXI Transmission Project
The Spoon River project is a MISO-approved 46-mile transmission line to be constructed in northwest Illinois. In September 2015, the ICC granted a certificate of public convenience and necessity and project approval for the Spoon River project.
Federal
Ameren Illinois Electric Transmission Rate Refund
In July 2012, the FERC issued an order concluding that Ameren Illinois improperly included acquisition premiums, including goodwill, in determining the common equity used in its electric transmission formula rate and thereby inappropriately recovered a higher amount from its electric transmission customers. The order requiredenable Ameren Illinois to make refundsrecover its costs and to customers for such improperly included amounts.earn a reasonable return on investments when the rate changes go into effect.
ATXI’s Illinois Rivers Project
In July 2015,August 2017, the FERC approved a settlement agreement between Ameren Illinois andCircuit Court for Edgar County dismissed several of ATXI’s condemnation cases related to one line segment in the affected customers.Illinois Rivers project. The settlement agreement required Ameren Illinois to make refunds and payments of $8estimated line segment capital expenditure investment is approximately $85 million, to electric transmission customers, all of which $36 million was paid in 2015.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 settlement agreement alsocourt found that required Amerennotice 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 takecomplete 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 actions, such as reducing common equity for electric transmission ratemaking purposes on a prospective basis. The transmission rates that became effective on January 1, 2016, reflecteight line segments of the Illinois Rivers project are not affected by these adjustments.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 the FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In December 2015, an administrative law judgeSeptember 2016, the FERC issued an initial decisiona final order in the November 2013 complaint case, that would lowerwhich lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32% and would require, or a 10.82% total allowed return on common equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. In 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the 15-month period ending February 2015.November 2013 complaint case. The 10.82% total allowed base return on common equity has been reflected in rates since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the initial decision was based on multiple inputs, including observable market data for the six months ended June 30, 2015. The FERC is expected to issueissues a final order onin the November 2013February 2015 complaint case, by October 2016.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%. The initial decision fromtariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which will subsequently requirecase. If approved by the FERC, approval, is expected to be issued by June 2016.
On January 6, 2015, a FERC-approved incentive adder of up to 50 basis points onit would lower the allowed base return on common equity for ourthe 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 became effective. BeginningRTO. It would also require customer refunds, with its January 6, 2015interest, 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 incentive adder will reduce any refundcurrent 10.82% total return on common equity.The timing of the issuance of the final order in the February 2015 complaint 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 customers relatingissue a final order. Second, in the second quarter of 2017, the United States Court of Appeals for the District of
Columbia Circuit vacated and remanded to the FERC an order in a reduction ofseparate case in which the FERC established the allowed base return on common equity frommethodology used in the two MISO complaint cases described above. Ameren is unable to predict the impact of the outcome of the United States Court of Appeals for the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time.
In September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion 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 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, 2015, Ameren and Ameren Illinois had current regulatory liabilities of $45 million and $32 million, respectively, representing their estimates of the potential refunds
from the November 12, 2013 refund effective date through December 31, 2015.2017, Ameren and Ameren Illinois recorded current regulatory liabilities of $42 million and $25 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed base returnreturns on common equity in the initial decision for the November 2013 complaint case refund period, and the observable market data for the six months ended December 31, 2015, forin the February 2015 complaint case refund period. Ameren’s andcase. Ameren Illinois’ liabilities also reflect the January 6, 2015 incentive adder discussed above. Ameren Missouri did not record a liability as of December 31, 2015, and it does not expect that a reduction in the FERC-allowed base return on common equity for MISO transmission owners 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 the second quarter of 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, 20152017 and 2014:
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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2015 | | 2014 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Current regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a)(b) | | $ | 37 |
| | $ | — |
| | $ | 37 |
| | | $ | 128 |
| | $ | — |
| | $ | 128 |
|
Under-recovered Illinois electric power costs(c) | | — |
| | 3 |
| | 3 |
| | | — |
| | 2 |
| | 2 |
|
Under-recovered PGA(c) | | — |
| | 8 |
| | 8 |
| | | — |
| | 20 |
| | 20 |
|
MTM derivative losses(d) | | 29 |
|
| 45 |
| | 74 |
| | | 32 |
| | 42 |
| | 74 |
|
Energy efficiency riders(e)
| | 23 |
| | — |
| | 23 |
| | | 3 |
| | — |
| | 3 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 103 |
| | 103 |
| | | — |
| | 65 |
| | 65 |
|
FERC revenue requirement reconciliation adjustment(a)(g)
| | — |
| | 8 |
| | 12 |
| | | — |
| | — |
| | 3 |
|
| Total current regulatory assets | | $ | 89 |
| | $ | 167 |
| | $ | 260 |
| | | $ | 163 |
| | $ | 129 |
| | $ | 295 |
|
| Noncurrent regulatory assets: | | | | | | | | | | | | | |
Pension and postretirement benefit costs(h) | | $ | 95 |
| | $ | 202 |
| | $ | 297 |
| | | $ | 148 |
| | $ | 275 |
| | $ | 423 |
|
Income taxes(i) | | 254 |
| | 4 |
| | 258 |
| | | 253 |
| | 3 |
| | 256 |
|
Asset retirement obligations(j) | | — |
| | 4 |
| | 4 |
| | | — |
| | 5 |
| | 5 |
|
Callaway costs(a)(k) | | 32 |
| | — |
| | 32 |
| | | 36 |
| | — |
| | 36 |
|
Unamortized loss on reacquired debt(a)(l) | | 69 |
| | 69 |
| | 138 |
| | | 72 |
| | 80 |
| | 152 |
|
Contaminated facilities costs(m) | | — |
| | 230 |
| | 230 |
| | | — |
| | 251 |
| | 251 |
|
MTM derivative losses(d) | | 15 |
|
| 175 |
| | 190 |
|
|
| 14 |
| | 144 |
| | 158 |
|
Storm costs(a)(n) | | — |
| | 9 |
| | 9 |
| | | — |
| | 3 |
| | 3 |
|
Demand-side costs before the MEEIA implementation(a)(o) | | 31 |
| | — |
| | 31 |
| | | 44 |
| | — |
| | 44 |
|
Workers’ compensation claims(p) | | 6 |
| | 7 |
| | 13 |
| | | 7 |
| | 7 |
| | 14 |
|
Credit facilities fees(q) | | 4 |
| | — |
| | 4 |
| | | 5 |
| | — |
| | 5 |
|
Construction accounting for pollution control equipment(a)(r) | | 20 |
| | — |
| | 20 |
| | | 21 |
| | — |
| | 21 |
|
Solar rebate program(a)(s) | | 74 |
| | — |
| | 74 |
| | | 88 |
| | — |
| | 88 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 62 |
| | 62 |
| | | — |
| | 101 |
| | 101 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 5 |
| | 11 |
| | | — |
| | 8 |
| | 12 |
|
| Other | | 5 |
| | 4 |
| | 9 |
| | | 7 |
| | 6 |
| | 13 |
|
| Total noncurrent regulatory assets | | $ | 605 |
| | $ | 771 |
| | $ | 1,382 |
| | | $ | 695 |
| | $ | 883 |
| | $ | 1,582 |
|
| Current regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(b) | | $ | 9 |
| | $ | — |
| | $ | 9 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Over-recovered Illinois electric power costs(c) | | — |
| | 6 |
| | 6 |
| | | — |
| | 26 |
| | 26 |
|
Over-recovered PGA(c) | | 3 |
| | — |
| | 3 |
| | | 2 |
| | 25 |
| | 27 |
|
MTM derivative gains(d) | | 16 |
| | 1 |
| | 17 |
|
| | 16 |
| | 1 |
| | 17 |
|
FERC revenue requirement reconciliation adjustment(g) | | — |
| | — |
| | — |
| | | — |
| | 11 |
| | 11 |
|
Estimated refund for FERC complaint cases, orders, and audit findings(t) | | — |
| | 32 |
| | 45 |
| | | — |
| | 21 |
| | 25 |
|
| Total current regulatory liabilities | | $ | 28 |
| | $ | 39 |
| | $ | 80 |
| | | $ | 18 |
| | $ | 84 |
| | $ | 106 |
|
| Noncurrent regulatory liabilities: | | | | | | | | | | | | | |
Income taxes(u) | | $ | 36 |
| | $ | 6 |
| | $ | 42 |
| | | $ | 41 |
| | $ | 14 |
| | $ | 55 |
|
Uncertain tax positions tracker(v) | | 6 |
| | — |
| | 6 |
| | | 7 |
| | — |
| | 7 |
|
Removal costs(w) | | 933 |
| | 671 |
| | 1,605 |
| | | 886 |
| | 643 |
| | 1,529 |
|
Asset retirement obligation(j) | | 167 |
| | — |
| | 167 |
| | | 182 |
| | — |
| | 182 |
|
Bad debt riders(x) | | — |
| | 6 |
| | 6 |
| | | — |
| | 7 |
| | 7 |
|
Pension and postretirement benefit costs tracker(y) | | 19 |
| | — |
| | 19 |
| | | 24 |
| | — |
| | 24 |
|
Energy efficiency riders(e) | | — |
| | 36 |
| | 36 |
| | | — |
| | 39 |
| | 39 |
|
Renewable energy credits(z) | | — |
| | 12 |
| | 12 |
| | | 1 |
| | — |
| | 1 |
|
Storm tracker(aa) | | 9 |
| | — |
| | 9 |
| | | 6 |
| | — |
| | 6 |
|
| Other | | 2 |
| | 1 |
| | 3 |
| | | — |
| | — |
| | — |
|
| Total noncurrent regulatory liabilities | | $ | 1,172 |
| | $ | 732 |
| | $ | 1,905 |
| | | $ | 1,147 |
| | $ | 703 |
| | $ | 1,850 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Other | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
| Total current regulatory assets | | $ | 56 |
| | $ | 87 |
| | $ | 144 |
| | | $ | 35 |
| | $ | 108 |
| | $ | 149 |
|
| Noncurrent regulatory assets: | | | | | | | | | | | | | |
Pension and postretirement benefit costs(i) | | $ | 84 |
| | $ | 215 |
| | $ | 299 |
| | | $ | 175 |
| | $ | 319 |
| | $ | 494 |
|
Income taxes(j) | | 139 |
| | 56 |
| | 197 |
| | | 229 |
| | 1 |
| | 230 |
|
Uncertain tax positions tracker(a)(k) | | 5 |
| | — |
| | 5 |
| | | 7 |
| | — |
| | 7 |
|
ARO(l) | | — |
| | 1 |
| | 1 |
| | | — |
| | 3 |
| | 3 |
|
Callaway costs(a)(m) | | 25 |
| | — |
| | 25 |
| | | 29 |
| | — |
| | 29 |
|
Unamortized loss on reacquired debt(a)(n) | | 61 |
| | 49 |
| | 110 |
| | | 65 |
| | 59 |
| | 124 |
|
Environmental cost riders(o) | | — |
| | 173 |
| | 173 |
| | | — |
| | 196 |
| | 196 |
|
MTM derivative losses(d) | | 4 |
|
| 192 |
| | 196 |
|
|
| 9 |
| | 178 |
| | 187 |
|
Storm costs(a)(p) | | — |
| | 10 |
| | 10 |
| | | — |
| | 15 |
| | 15 |
|
Demand-side costs before the MEEIA implementation(a)(q) | | 11 |
| | — |
| | 11 |
| | | 18 |
| | — |
| | 18 |
|
Workers’ compensation claims(r) | | 5 |
| | 7 |
| | 12 |
| | | 6 |
| | 7 |
| | 13 |
|
Credit facilities fees(s) | | 3 |
| | — |
| | 3 |
| | | 4 |
| | — |
| | 4 |
|
Construction accounting for pollution control equipment(a)(t) | | 18 |
| | — |
| | 18 |
| | | 19 |
| | — |
| | 19 |
|
Solar rebate program(a)(u) | | 31 |
| | — |
| | 31 |
| | | 49 |
| | — |
| | 49 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 54 |
| | 54 |
| | | — |
| | 23 |
| | 23 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 16 |
| | 27 |
| | | — |
| | 8 |
| | 10 |
|
FEJA energy-efficiency riders(a)(v) | | — |
| | 41 |
| | 41 |
| | | — |
| | — |
| | — |
|
| Other | | 9 |
| | 8 |
| | 17 |
| | | 9 |
| | 7 |
| | 16 |
|
| Total noncurrent regulatory assets | | $ | 395 |
| | $ | 822 |
| | $ | 1,230 |
| | | $ | 619 |
| | $ | 816 |
| | $ | 1,437 |
|
| Current regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(b) | | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Over-recovered Illinois electric power costs(c) | | — |
| | 16 |
| | 16 |
| | | — |
| | 25 |
| | 25 |
|
Over-recovered PGA(c) | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
MTM derivative gains(d) | | 13 |
| | — |
| | 13 |
|
| | 12 |
| | 11 |
| | 23 |
|
Energy-efficiency riders(e) | | 2 |
| | 40 |
| | 42 |
| | | — |
| | — |
| | — |
|
Estimated refund for FERC complaint case(w) | | — |
| | 25 |
| | 42 |
| | | — |
| | 42 |
| | 62 |
|
| Other | | — |
| | 10 |
| | 10 |
| | | — |
| | — |
| | — |
|
| Total current regulatory liabilities | | $ | 19 |
| | $ | 92 |
| | $ | 128 |
| | | $ | 12 |
| | $ | 78 |
| | $ | 110 |
|
| Noncurrent regulatory liabilities: | | | | | | | | | | | | | |
Income taxes(j) | | $ | 1,392 |
| | $ | 842 |
| | $ | 2,323 |
| | | $ | 33 |
| | $ | 4 |
| | $ | 37 |
|
Uncertain tax positions tracker(k) | | 2 |
| | — |
| | 2 |
| | | 3 |
| | — |
| | 3 |
|
Asset removal costs(x) | | 995 |
| | 725 |
| | 1,725 |
| | | 970 |
| | 697 |
| | 1,669 |
|
ARO(l) | | 223 |
| | — |
| | 223 |
| | | 162 |
| | — |
| | 162 |
|
Bad debt rider(y) | | — |
| | 2 |
| | 2 |
| | | — |
| | 3 |
| | 3 |
|
Pension and postretirement benefit costs tracker(z) | | 35 |
| | — |
| | 35 |
| | | 35 |
| | — |
| | 35 |
|
Energy-efficiency riders(e) | | — |
| | — |
| | — |
| | | — |
| | 45 |
| | 45 |
|
Renewable energy credits and zero-emission credits(aa) | | — |
| | 58 |
| | 58 |
| | | — |
| | 15 |
| | 15 |
|
Storm tracker(ab) | | 6 |
| | — |
| | 6 |
| | | 7 |
| | — |
| | 7 |
|
| Other | | 11 |
| | 2 |
| | 13 |
| | | 5 |
| | 4 |
| | 9 |
|
| Total noncurrent regulatory liabilities | | $ | 2,664 |
| | $ | 1,629 |
| | $ | 4,387 |
| | | $ | 1,215 |
| | $ | 768 |
| | $ | 1,985 |
|
| |
| (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. Beginning in January 2014, theThe MEEIA rider allowedallows 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, and its net shared benefits.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 lost revenuesthe 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 12 months 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. Subject to ICC approval, these amountsAny under-recovery or over-recovery will be collectedrecovered from or refunded to customers with interest within two years. |
| |
| (g) | Ameren Illinois'Illinois’ and ATXI'sATXI’s annual revenue requirement reconciliation adjustments 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’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. |
| |
(i)(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. Thischanges 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. |
| |
(j)(k) | The tracker is amortized over three years, beginning from the date the amounts are included in rates. See Note 12 – Income Taxes for additional information. |
| |
| (l) | 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 and Investments.Obligations. |
| |
(k)(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. |
| |
(l)(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. |
| |
(m)(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. |
| |
(n)(p) | Storm costs from 2013, 2015, and 20152016 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in 2013 and 2015, respectively.the year the storm occurred. |
| |
(o)(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. |
| |
(p)(r) | The period of recovery will depend on the timing of actual expenditures. |
| |
(q)(s) | Ameren Missouri’s costs incurred to enter into and maintain the Missouri Credit Agreement. Additional costs were incurred in December 2014 to amend and restate the Missouri Credit Agreement. These costs are being amortized over the life of the credit facility ending in December 2019, 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. |
| |
(r)(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, which is currently through 2033. |
| |
(s)(u) | Costs associated with Ameren Missouri'sMissouri’s solar rebate program beginning in August 2012 to fulfill its renewable energy portfolio requirement. These costsCosts incurred from 2010 to 2014 are being amortized over three years, beginninga two-year period that began in June 2015.April 2017 as modified per the MoPSC March 2017 electric rate order. Costs incurred from 2015 to 2016 are being amortized over a three-year period that began in April 2017. |
| |
(t)(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. See Ameren Illinois Electric Transmission Rate Refund andthe February 2015 FERC Complaint CasesCase discussed above. |
| |
(u) | 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. |
| |
(v) | The tracker is amortized over three years, beginning from the date the amounts are included in rates. See Note 13 – Income Taxes for additional information. |
| |
(w)(x) | Estimated funds collected for the eventual dismantling and removal of plant retired from service, net of salvage value, upon retirement related to our rate-regulated operations.value. |
| |
(x)(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 20132015 was refunded to customers from June 2014 through May 2015. The over-recovery relating to 2014 will be refunded to customers from June 2015 through May 2016. The over-recovery relating to 2015 will be refunded to customers from June 2016 through May 2017. The over-recovery relating to 2016 is being refunded to customers from June 2017 through May 2018. The over-recovery relating to 2017 will be refunded to customers from June 2018 through May 2019. |
| |
(y)(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 a future electric regulatory rate case.review. |
| |
(z)(aa) | The Ameren Missouri balance includes the costs of renewable energy credits to fulfill Ameren Missouri's renewable energy portfolio requirement from August 2012 through December 2013, which were less than the amount included in rates. These costs are being amortized over three years beginning in June 2015. The Ameren Illinois balance includes fundsFunds 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. |
| |
(aa)(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 five years, beginninga five-year period that began in June 2015. For periods after December 2014, the amortization period will be determined in a futureMoPSC’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 mechanisms for storm costs.mechanism. |
Ameren, Ameren Missouri, and Ameren Illinois continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatoryRegulatory 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 PLANT,EQUIPMENT, NET
The following table presents property, plant, and plant,equipment, net, for each of the Ameren Companies at December 31, 20152017 and 20142016:
| | | | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) |
| 2015 | | | | | | | | | |
| Property and plant, at original cost: | | | | | | | | | |
| Electric | | $ | 17,521 |
| | $ | 7,253 |
| | $ | 387 |
| | $ | 25,161 |
| |
| 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 | | 445 |
| | 1,997 |
| | — |
| | 2,442 |
| | 474 |
| | 2,419 |
| | — |
| | 2,893 |
|
Other(c) | | | 922 |
| | 757 |
| | 242 |
| | 1,921 |
|
| | | 17,966 |
| | 9,250 |
| | 387 |
| | 27,603 |
| | 19,495 |
| | 11,123 |
| | 1,409 |
| | 32,027 |
|
| Less: Accumulated depreciation and amortization | | 7,460 |
| | 2,632 |
| | 255 |
| | 10,347 |
| | 8,305 |
| | 3,082 |
| | 246 |
| | 11,633 |
|
| | | 10,506 |
| | 6,618 |
| | 132 |
| | 17,256 |
| | 11,190 |
| | 8,041 |
| | 1,163 |
| | 20,394 |
|
| Construction work in progress: | | | | | | | | | | | | | | | | |
| Nuclear fuel in process | | 275 |
| | — |
| | — |
| | 275 |
| | 148 |
| | — |
| | — |
| | 148 |
|
| Other | | 402 |
| | 230 |
| | 636 |
| | 1,268 |
| | 413 |
| | 252 |
| | 259 |
| | 924 |
|
| Property and plant, net | | $ | 11,183 |
| | $ | 6,848 |
| | $ | 768 |
| | $ | 18,799 |
| |
| 2014 | | | | | | | | | |
| Property and plant, at original cost: | | | | | | | | | |
| Electric | | $ | 17,052 |
| | $ | 6,517 |
| | $ | 344 |
| | $ | 23,913 |
| |
| Property, plant, and equipment, net | | | $ | 11,751 |
| | $ | 8,293 |
| | $ | 1,422 |
| | $ | 21,466 |
|
| 2016 | | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | | |
| Electric generation | | | $ | 10,911 |
| | $ | — |
| | $ | — |
| | $ | 10,911 |
|
| Electric distribution | | | 5,563 |
| | 5,287 |
| | — |
| | 10,850 |
|
| Electric transmission | | | 1,151 |
| | 2,016 |
| | 712 |
| | 3,879 |
|
| Natural gas | | 431 |
| | 1,854 |
| | — |
| | 2,285 |
| | 455 |
| | 2,186 |
| | — |
| | 2,641 |
|
Other(c) | | | 879 |
| | 719 |
| | 239 |
| | 1,837 |
|
| | | 17,483 |
| | 8,371 |
| | 344 |
| | 26,198 |
| | 18,959 |
| | 10,208 |
| | 951 |
| | 30,118 |
|
| Less: Accumulated depreciation and amortization | | 7,086 |
| | 2,422 |
| | 251 |
| | 9,759 |
| | 7,880 |
| | 2,850 |
| | 231 |
| | 10,961 |
|
| | | 10,397 |
| | 5,949 |
| | 93 |
| | 16,439 |
| | 11,079 |
| | 7,358 |
| | 720 |
| | 19,157 |
|
| Construction work in progress: | | | | | | | | | | | | | | | | |
| Nuclear fuel in process | | 209 |
| | — |
| | — |
| | 209 |
| | 206 |
| | — |
| | — |
| | 206 |
|
| Other | | 261 |
| | 216 |
| | 299 |
| | 776 |
| | 193 |
| | 111 |
| | 446 |
| | 750 |
|
| Property and plant, net | | $ | 10,867 |
| | $ | 6,165 |
| | $ | 392 |
| | $ | 17,424 |
| |
| Property, plant, and equipment, net | | | $ | 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 $233$233 million and $232 million at December 31, 20152017 and 2014.2016, respectively. The total accumulated depreciation associated with the two CTs was $72$83 million and $66$77 million at December 31, 20152017 and 2014,2016, respectively. In addition,See Note 5 – Long-term Debt and Equity Financings for additional information on these capital lease agreements. |
| |
| (b) | The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri has investments in debt securities,Missouri’s hydro generating assets which were classified as held-to-maturityhave useful lives of up to 150 years, 20 to 80 years for electric distribution, 50 to 75 years for electric transmission, 20 to 80 years for natural gas, and recorded in "Other assets", related5 to the two CTs from the city of Bowling Green55 years for other. |
| |
| (c) | Other property, plant, and Audrain County. equipment includes assets used to support electric and natural gas services. |
Capitalized software costs are classified within “Property, Plant, and Equipment, Net” on the balance sheet and are amortized on a straight-line basis over the expected period of benefit, ranging from 5 to 10 years. The following table presents the 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, 2015 and 2014,2017, the carrying valueestimated amortization expense of these debt securities was $288 million and $294 million, respectively.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, 20152017, 20142016, and 20132015, 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 |
|
| 2015 | $ | 235 |
| | $ | 85 |
| | $ | 92 |
| 235 |
| | 85 |
| | 92 |
|
| 2014 | 181 |
| | 72 |
| | 59 |
| |
| 2013 | 175 |
| | 74 |
| | 86 |
| |
| Accrued nuclear fuel expenditures: | | | | | | | | | | |
| 2017 | | 10 |
| | 10 |
| | (b) |
|
| 2016 | | 20 |
| | 20 |
| | (b) |
|
| 2015 | 16 |
| | 16 |
| | (b) |
| 16 |
| | 16 |
| | (b) |
|
| 2014 | 13 |
| | 13 |
| | (b) |
| |
| 2013 | 8 |
| | 8 |
| | (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
The Credit Agreements provide a total of $2.1 billion of credit cumulatively through theirmaturity in December 20192021. The maturity date. The facilities include 24date 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 $115$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 which will expire in December 2019 (the amount being each borrower's "Borrowing Sublimit"):facility: |
| | | | | | | |
| | | Missouri Credit Agreement | Illinois Credit Agreement |
| Ameren | | $ | 700 |
| $ | 500 |
|
| Ameren Missouri | | 800 |
| (a) |
|
| Ameren Illinois | | (a) |
| 800 |
|
|
| | | | | | | |
| | | Missouri Credit Agreement | Illinois Credit Agreement |
| Ameren (parent) | | $ | 700 |
| $ | 500 |
|
| Ameren Missouri | | 800 |
| (a) |
|
| Ameren Illinois | | (a) |
| 800 |
|
Ameren hasThe 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. The principal amount of each revolving loan owed by a borrower under any of the Credit Agreements to which it is a party will beAmeren (parent) borrowings are due and payable no later than the maturity date of suchthe Credit Agreement. The principal amount of each revolving loan owed byAgreements. Ameren Missouri orand Ameren Illinois borrowings under the applicable Credit Agreement will beare due and payable no later than the earlier of the maturity date or 364 days after the originating date of such loan. The Credit Agreements are currently scheduled to mature in December 2019, but the maturity date may be extended once or twice for additional one-year periods upon mutual consent of the borrowers and lenders.borrowing.
The obligations of allthe 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, or for paying fees and expenses incurred in connection with the Credit Agreements. Both of the Credit Agreements are available to Ameren to support issuances under Ameren's commercial paper program, subject to borrowing sublimits.arrangements. 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, 2015,2017, 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 $1.8 billion.$1.6 billion.
Ameren, Ameren Missouri, and Ameren Illinois did not borrow under the Credit Agreements for the years ended December 31, 20152017 and 2014.2016.
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, 20152017 and 20142016:
| | | | | Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated | | Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated |
| 2015 | | | | | |
| 2017 | | | | | |
| Average daily commercial paper outstanding | | $ | 721 |
| | $ | 42 |
| $ | 4 |
| $ | 767 |
| | $ | 573 |
| | $ | 5 |
| $ | 90 |
| $ | 668 |
|
| Outstanding borrowings at period-end | | 301 |
| | — |
| — |
| 301 |
| | 383 |
| | 39 |
| 62 |
| 484 |
|
| Weighted-average interest rate | | 0.57 | % | | 0.50 | % | 0.44 | % | 0.55 | % | | 1.30 | % | | 1.24 | % | 1.35 | % | 1.31 | % |
Peak commercial paper during period(a) | | $ | 874 |
| | $ | 294 |
| $ | 48 |
| $ | 1,108 |
| |
Peak outstanding commercial paper during period(a) | | | $ | 841 |
| | $ | 64 |
| $ | 469 |
| $ | 948 |
|
| Peak interest rate | | 0.91 | % | | 0.60 | % | 0.60 | % | 0.91 | % | | 1.90 | % | | 1.78 | % | 2.00 | % | 2.00 | % |
| 2014 | | | | | |
| 2016 | | | | | |
| Average daily commercial paper outstanding | | $ | 423 |
| | $ | 110 |
| $ | 165 |
| $ | 639 |
| | $ | 440 |
| | $ | 60 |
| $ | 52 |
| $ | 552 |
|
| Outstanding borrowings at period-end | | 585 |
| | 97 |
| 32 |
| 714 |
| | 507 |
| | — |
| 51 |
| 558 |
|
| Weighted-average interest rate | | 0.36 | % | | 0.38 | % | 0.32 | % | 0.36 | % | | 0.82 | % | | 0.74 | % | 0.69 | % | 0.80 | % |
Peak commercial paper during period(a) | | $ | 625 |
| | $ | 495 |
| $ | 300 |
| $ | 910 |
| |
Peak outstanding commercial paper during period(a) | | | $ | 574 |
| | $ | 208 |
| $ | 195 |
| $ | 839 |
|
| Peak interest rate | | 0.75 | % | | 0.70 | % | 0.60 | % | 0.75 | % | | 1.05 | % | | 0.85 | % | 0.90 | % | 1.05 | % |
| |
| (a) | The timing of peak outstanding commercial paper issuances varies by company, and thereforecompany. Therefore, the sum of the peak amounts presented by company mightthe companies may not equal the Ameren Consolidatedconsolidated peak commercial paper issuancesamount 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, 2015,2017, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 51%53%, 49%48%, and 47%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. In addition, under the Illinois Credit Agreement and, by virtue of the cross-default provisions of the Missouri Credit Agreement, under the Missouri Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of2.0 to 1.0. However, the interest coverage requirement applies only at such times as Ameren does not have a senior long-term unsecured credit rating of at least Baa3 from Moody's or BBB- from S&P. As of December 31, 2015, Ameren exceeded the rating requirements; therefore, the interest coverage requirement was not applicable. Any failure by a borrower to satisfy a financial covenant constitutes an immediate default under the applicable Credit Agreement.
The Credit Agreements contain default provisions that apply separately to each borrower; provided, however, thatborrower. 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 $75$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 thereunder 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, 20152017.
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, 2015,2017, was 0.11% (20141.19% (2016 – 0.19%0.52%).
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, 2015, 2014,2017, 2016, and 2013.2015.
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, 20152017 and 20142016:
|
| | | | | | | |
| | 2015 | | 2014 |
| Ameren (Parent): | | | |
| 2.70% Senior unsecured notes due 2020 | $ | 350 |
| | $ | — |
|
| 3.65% Senior unsecured notes due 2026 | 350 |
| | — |
|
| Total long-term debt, gross | 700 |
| | — |
|
Less: Unamortized debt issuance costs(a) | (6 | ) | | — |
|
| Long-term debt, net | $ | 694 |
| | $ | — |
|
| Ameren Missouri: | | | |
Senior secured notes:(b) | | | |
| 4.75% Senior secured notes due 2015 | — |
| | 114 |
|
| 5.40% Senior secured notes due 2016 | 260 |
| | 260 |
|
| 6.40% Senior secured notes due 2017 | 425 |
| | 425 |
|
6.00% Senior secured notes due 2018(c) | 179 |
| | 179 |
|
| 5.10% Senior secured notes due 2018 | 199 |
| | 199 |
|
6.70% Senior secured notes due 2019(c) | 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(c) | 350 |
| | 350 |
|
3.90% Senior secured notes due 2042(c) | 485 |
| | 485 |
|
| 3.65% Senior secured notes due 2045 | 250 |
| | — |
|
| Environmental improvement and pollution control revenue bonds: | | | |
1992 Series due 2022(d)(e) | 47 |
| | 47 |
|
1993 5.45% Series due 2028(f) | (f) |
| | (f) |
|
1998 Series A due 2033(d)(e) | 60 |
| | 60 |
|
1998 Series B due 2033(d)(e) | 50 |
| | 50 |
|
1998 Series C due 2033(d)(e) | 50 |
| | 50 |
|
| Capital lease obligations: | | | |
| City of Bowling Green capital lease (Peno Creek CT) due 2022 | 48 |
| | 54 |
|
| Audrain County capital lease (Audrain County CT) due 2023 | 240 |
| | 240 |
|
| Total long-term debt, gross | 4,135 |
| | 4,005 |
|
| Less: Unamortized discount and premium | (6 | ) | | (6 | ) |
Less: Unamortized debt issuance costs(a) | (19 | ) | | (18 | ) |
| Less: Maturities due within one year | (266 | ) | | (120 | ) |
| Long-term debt, net | $ | 3,844 |
| | $ | 3,861 |
|
|
| | | | | | | |
| | 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 |
|
|
| | | | | | | |
| | 2015 | | 2014 |
| Ameren Illinois: | | | |
| Senior secured notes: | | | |
6.20% Senior secured notes due 2016(g) | $ | 54 |
| | $ | 54 |
|
6.25% Senior secured notes due 2016(h) | 75 |
| | 75 |
|
6.125% Senior secured notes due 2017(h)(i) | 250 |
| | 250 |
|
6.25% Senior secured notes due 2018(h)(i) | 144 |
| | 144 |
|
9.75% Senior secured notes due 2018(h)(i) | 313 |
| | 313 |
|
2.70% Senior secured notes due 2022(h)(i) | 400 |
| | 400 |
|
3.25% Senior secured notes due 2025(h) | 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(h) | 60 |
| | 60 |
|
6.70% Senior secured notes due 2036(h) | 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(g) | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(h) | 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(h) | 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(h) | 250 |
| | — |
|
| Environmental improvement and pollution control revenue bonds: | | | |
5.90% Series 1993 due 2023(j) | (j) |
| | (j) |
|
5.70% 1994A Series due 2024(k) | (k) |
| | (k) |
|
1993 Series B-1 due 2028(e)(l) | 17 |
| | 17 |
|
| Total long-term debt, gross | 2,496 |
| | 2,246 |
|
| Less: Unamortized discount and premium | (7 | ) | | (5 | ) |
Less: Unamortized debt issuance costs(a) | (18 | ) | | (17 | ) |
| Less: Maturities due within one year | (129 | ) | | — |
|
| Long-term debt, net | $ | 2,342 |
| | $ | 2,224 |
|
| Ameren consolidated long-term debt, net | $ | 6,880 |
| | $ | 6,085 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
6.125% Senior secured notes due 2017(g)(h) | $ | — |
| | $ | 250 |
|
6.25% Senior secured notes due 2018(g)(h) | 144 |
| | 144 |
|
9.75% Senior secured notes due 2018(g)(h) | 313 |
| | 313 |
|
2.70% Senior secured notes due 2022(g)(h) | 400 |
| | 400 |
|
5.90% First mortgage bonds due 2023(i) | (i) |
| | (i) |
|
5.70% First mortgage bonds due 2024(j) | (j) |
| | (j) |
|
3.25% Senior secured notes due 2025(g) | 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(g) | 60 |
| | 60 |
|
1993 Series B-1 Senior unsecured notes due 2028(d)(k) | 17 |
| | 17 |
|
6.70% Senior secured notes due 2036(g) | 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(l) | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(g) | 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(g) | 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(g) | 490 |
| | 490 |
|
3.70% First mortgage bonds due 2047(m) | 500 |
| | — |
|
| Total long-term debt, gross | 2,857 |
| | 2,607 |
|
| Less: Unamortized discount and premium | (3 | ) | | — |
|
| Less: Unamortized debt issuance costs | (24 | ) | | (19 | ) |
| Less: Maturities due within one year | (457 | ) | | (250 | ) |
| Long-term debt, net | $ | 2,373 |
| | $ | 2,338 |
|
| ATXI: | | | |
3.43% Senior notes due 2050(n) | $ | 450 |
| | $ | — |
|
| Total long-term debt, gross | 450 |
| | — |
|
| Less: Unamortized debt issuance costs | (2 | ) | | — |
|
| Long-term debt, net | $ | 448 |
| | $ | — |
|
| Ameren consolidated long-term debt, net | $ | 7,094 |
| | $ | 6,595 |
|
| |
| (a) | Reflects the adoption of the new authoritative accounting guidance for the presentation of debt issuance costs. See Note 1 – Summary of Significant Accounting Policies for additional information. |
| |
(b) | 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 untilbefore 2042. |
| |
(c)(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. |
| |
(d)(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. |
| |
(e)(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 20152017 and 20142016 were as follows: |
| | | | 2015 | | 2014 | 2017 | | 2016 |
| Ameren Missouri 1992 Series due 2022 | 0.06% | | 0.10% | 1.43% | | 0.66% |
| Ameren Missouri 1998 Series A due 2033 | 0.24% | | 0.26% | 1.77% | | 0.91% |
| Ameren Missouri 1998 Series B due 2033 | 0.24% | | 0.27% | 1.75% | | 0.92% |
| Ameren Missouri 1998 Series C due 2033 | 0.24% | | 0.26% | 1.73% | | 0.97% |
| Ameren Illinois 1993 Series B-1 due 2028 | 0.49% | | 0.21% | 1.08% | | 0.70% |
| |
(f)(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) | Payments due to the lessor under these capital lease obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the lessor and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the capital lease agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the capital lease obligations and the related investments in debt securities, recorded in "Other Assets," was $276 million 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 the CILCO mortgage indenture. The notes have a fall-away lien provision, 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 $1 million remains outstanding). |
| |
(h) | These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinoisits 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 the Ameren Illinoisits 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 until 2024.away. |
| |
(i)(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.
| |
(j)(i) | These bonds are first mortgage bonds issued by Ameren Illinois under the CILCOits 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. |
| |
(k)(j) | These bonds are first mortgage bonds issued by Ameren Illinois under the Ameren Illinoisits 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. |
| |
(l)(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, 20152017:
| | | | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | Ameren Consolidated | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated |
| 2016 | $ | — |
| | $ | 266 |
| | $ | 129 |
| | $ | 395 |
| |
| 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 |
|
| 2022 | | — |
| | 56 |
| | 400 |
| | 50 |
| | 506 |
|
| Thereafter | 350 |
| | 2,382 |
| | 1,660 |
| | 4,392 |
| 350 |
| | 2,867 |
| | 2,000 |
| | 400 |
| | 5,617 |
|
| Total | $ | 700 |
| | $ | 4,135 |
| | $ | 2,496 |
| | $ | 7,331 |
| $ | 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 $252 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, 20152017 and 20142016:
| | | | | Redemption Price(per share) | | 2015 | | 2014 | | 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 November 15, 2020, with interest payable semiannually on May 15 and November 15 of each year, beginning May 15, 2016. Ameren (parent) received proceeds of $348 million, which were used to repay a portion of short-term debt.
In November 2015, Ameren (parent) issued $350 million of 3.65% senior unsecured notes due February 15, 2026, with interest payable semiannually on February 15 and August 15 of each year, beginning February 15, 2016. Ameren (parent) received proceeds of $347 million, which were used to repay a portion of short-term debt.
In May 2014, Ameren (parent) repaid at maturity $425 million of its 8.875% senior unsecured notes, plus accrued interest. The notes were repaid with proceeds from commercial paper issuances.
In June 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 May 2014,2017, 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, 2017 and 2016, DRPlus participant funds of $8 million were reflected on Ameren’s consolidated balance sheets in “Other current assets.”
In October 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 20132015 through 2015,2017, 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'sMissouri’s 5.40% senior secured notes matured and were repaid with cash on hand and commercial paper borrowings.
In April 2015,June 2016, Ameren Missouri issued $250$150 million of 3.65% senior secured notes due in April 15, 2045, with interest payable semiannually onin April 15 and October 15 of each year, beginning in October 15, 2015.2016. Ameren Missouri received proceeds of $247$148 million from the June 2016 issuance, which werewas 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 onin April 1, 2015.
For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
Ameren Illinois
In April 2014,November 2017, Ameren MissouriIllinois issued $350$500 million of 3.50% senior secured notes3.70% first mortgage bonds due April 15, 2024,December 2047, with interest payable semiannually on April 15June 1 and October 15December 1 of each year, beginning October 15, 2014.June 1, 2018. Ameren MissouriIllinois received proceeds of $348$492 million, which were used to repay at maturity $104outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $250 million of its 5.50%6.125% senior secured notes due May 15, 2014that matured in November 2017.
In June 2016, Ameren Illinois’ $54 million principal amount of 6.20% senior secured notes and to repay a portion$75 million principal amount of its short-term debt.
For information on Ameren Missouri's capital contributions6.25% senior secured notes matured and return of capital, refer to Capital Contributions and Return of Capital in Note 1 – Summary of Significant Accounting Policies.
Ameren Illinoiswere repaid with commercial paper borrowings.
In December 2015,2016, Ameren Illinois issued $250$240 million of 4.15% senior secured notes due in March 15, 2046, with interest payable semiannually onin March 15 and September, 15, beginning in March 15, 2016.2017. Ameren Illinois received proceeds of $245 million from the issuance, which were used to repay a portion of its short-term debt.
In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest: |
| | | |
| Senior Secured Notes | Principal Amount |
5.90% Series 1993 due 2023(a) | $ | 32 |
|
5.70% 1994A Series due 2024(a) | 36 |
|
| 1993 Series C-1 5.95% due 2026 | 35 |
|
| 1993 Series C-2 5.70% due 2026 | 8 |
|
| 5.40% 1998A Series due 2028 | 19 |
|
| 5.40% 1998B Series due 2028 | 33 |
|
| Total amount redeemed | $ | 163 |
|
| |
(a) | Less than $1 million principal amount of the bonds remains outstanding after redemption. |
In June 2014, Ameren Illinois issued $250 million of 4.30% senior secured notes due July 1, 2044, with interest payable semiannually on January 1 and July 1, beginning January 1, 2015. Ameren Illinois received proceeds of $246 million, which were used to repay a portion of its short-term debt.
In December 2014, Ameren Illinois issued $300 million of 3.25% senior secured notes due March 1, 2025, with interest payable semiannually on March 1 and September 1, beginning March 1, 2015. Ameren Illinois received proceeds of $298 million, which werewas 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 credit facilities, 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, 20152017, 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 | 3.8 |
| $ | 3,385 |
| | >2.5 | 104.0 |
| $ | 2,315 |
| | >2.0 | 4.8 |
| $ | 4,222 |
| | >2.5 | 95.4 |
| $ | 2,118 |
| |
| Ameren Illinois | >2.0 | 6.3 |
| 3,566 |
| (d) | >1.5 | 2.6 |
| 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 $9461,629 million and $204$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 the former IPits 1992 mortgage indenture. The amount of bonds issuable by Ameren Illinois is also subject to the lien restrictions contained in the Illinois Credit Agreement. |
| |
| (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, 20152017, 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, 20152017, 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, 20152017, 20142016, and 20132015:
| | | | 2015 | | 2014 | | 2013 | | 2017 | | 2016 | | 2015 | |
Ameren:(a) | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
| Allowance for equity funds used during construction | $ | 30 |
| | $ | 34 |
| | $ | 37 |
| | $ | 24 |
| | $ | 27 |
| | $ | 30 |
| |
| Interest income on industrial development revenue bonds | 27 |
| | 27 |
| | 27 |
| | 26 |
| | 27 |
| | 27 |
| |
Interest income (b) | 14 |
| | 10 |
| | 3 |
| | 8 |
| | 13 |
| | 14 |
| |
| Other | 3 |
| | 8 |
| (c) | 2 |
| | 1 |
| | 7 |
| | 3 |
| |
| Total miscellaneous income | $ | 74 |
| | $ | 79 |
| | $ | 69 |
| | $ | 59 |
| | $ | 74 |
| | $ | 74 |
| |
| Miscellaneous expense: | | | | | | | | | | | | |
| Donations | $ | 15 |
| | $ | 10 |
| | $ | 12 |
| | $ | 8 |
| | $ | 16 |
| | $ | 15 |
| |
| Other | 15 |
| | 12 |
| | 14 |
| | 13 |
| | 16 |
| | 15 |
| |
| Total miscellaneous expense | $ | 30 |
| | $ | 22 |
| | $ | 26 |
| | $ | 21 |
| | $ | 32 |
| | $ | 30 |
| |
| Ameren Missouri: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
| Allowance for equity funds used during construction | $ | 22 |
| | $ | 32 |
| | $ | 31 |
| | $ | 21 |
| | $ | 23 |
| | $ | 22 |
| |
| Interest income on industrial development revenue bonds | 27 |
| | 27 |
| | 27 |
| | 26 |
| | 27 |
| | 27 |
| |
| Interest income | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | 1 |
| |
| Other | 2 |
| | — |
| | — |
| | — |
| | 1 |
| | 2 |
| |
| Total miscellaneous income | $ | 52 |
| | $ | 60 |
| | $ | 58 |
| | $ | 48 |
| | $ | 52 |
| | $ | 52 |
| |
| Miscellaneous expense: | | | | | | | | | | | | |
| Donations | $ | 5 |
| | $ | 6 |
| | $ | 4 |
| | $ | 2 |
| | $ | 4 |
| | $ | 5 |
| |
| Other | 6 |
| | 6 |
| | 7 |
| | 6 |
| | 6 |
| | 6 |
| |
| Total miscellaneous expense | $ | 11 |
| | $ | 12 |
| | $ | 11 |
| | $ | 8 |
| | $ | 10 |
| | $ | 11 |
| |
| Ameren Illinois: | | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | | |
| Allowance for equity funds used during construction | $ | 8 |
| | $ | 2 |
| | $ | 6 |
| | $ | 3 |
| | $ | 4 |
| | $ | 8 |
| |
Interest income (b) | 12 |
| | 7 |
| | 2 |
| | 7 |
| | 12 |
| | 12 |
| |
| Other | 1 |
| | 8 |
| (c) | 2 |
| | 1 |
| | 5 |
| | 1 |
| |
| Total miscellaneous income | $ | 21 |
| | $ | 17 |
| | $ | 10 |
| | $ | 11 |
| | $ | 21 |
| | $ | 21 |
| |
| Miscellaneous expense: | | | | | | | | | | | | |
| Donations | $ | 5 |
| | $ | 4 |
| | $ | 4 |
| | $ | 5 |
| | $ | 6 |
| | $ | 5 |
| |
| Other | 7 |
| | 4 |
| | 5 |
| | 5 |
| | 6 |
| | 7 |
| |
| Total miscellaneous expense | $ | 12 |
| | $ | 8 |
| | $ | 9 |
| | $ | 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, 20152017 and 2014.2016. As of December 31, 2015,2017, these contracts ranextended through October 2018,2019, March 2021,2023, May 2032, and January 2019September 2021 for fuel oils, natural gas, power, and uranium, respectively.
| | | | Quantity (in millions, except as indicated) | Quantity (in millions, except as indicated) |
| | 2015 | 2014 | 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) | 35 | (b) | 35 | 50 | (b) | 50 | 28 |
| (b) |
| 28 |
| 30 |
| (b) |
| 30 |
|
| Natural gas (in mmbtu) | 30 | 151 | 181 | 28 | 108 | 136 | 24 |
| 139 |
| 163 |
| 25 |
| 129 |
| 154 |
|
| Power (in megawatthours) | 1 | 10 | 11 | 1 | 11 | 12 | 3 |
| 9 |
| 12 |
| 1 |
| 9 |
| 10 |
|
| Uranium (pounds in thousands) | 494 | (b) | 494 | 332 | (b) | 332 | 370 |
| (b) |
| 370 |
| 345 |
| (b) |
| 345 |
|
| |
| (a) | Fuel oils consistConsists of heating oil and ultra-low-sulfur diesel.diesel products. |
Authoritative accounting guidance regarding derivative instruments requires that allAll 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 it qualifies for hedge accounting. We also consider whetherthe resulting gains or losses resulting from such derivatives 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 regulatory liabilities in the period in which the change occurs. We
believe derivative losses and gains deferred as regulatory assets and regulatory liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and regulatory 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, 20152017 and 2014,2016, all contracts that qualifymet the definition of a derivative and were not eligible for hedge accounting receivethe NPNS exception received regulatory deferral.
Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under a master netting arrangement or similar agreement. The Ameren Companies did not elect to adopt this guidance for any eligible derivative instruments.
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, 20152017 and 20142016:
| | | | Balance Sheet Location | | Ameren Missouri | | Ameren Illinois | | Ameren | Balance Sheet Location | | Ameren Missouri | | Ameren Illinois | | Ameren | |
| 2015 | | | | | | | |
| 2017 | | | | | | | | |
| Fuel oils | | Other current assets | $ | 5 |
| $ | — |
| $ | 5 |
| |
| | | Other assets | | 2 |
| | — |
| | 2 |
| |
| Natural gas | | Other assets | | 1 |
| | — |
| | 1 |
| |
| Power | | Other current assets | | 9 |
| | — |
| | 9 |
| |
| | | Total assets (a) | $ | 17 |
| $ | — |
| $ | 17 |
| |
| Natural gas | | Other current liabilities | | 5 |
| | 12 |
| | 17 |
| |
| | | Other deferred credits and liabilities | | 3 |
| | 10 |
| | 13 |
| |
| Power | | Other current liabilities | | 1 |
| | 13 |
| | 14 |
| |
| | | Other deferred credits and liabilities | | — |
| | 182 |
| | 182 |
| |
| Uranium | | Other deferred credits and liabilities | | — |
| (b) | — |
| | — |
| (b) |
| | | Total liabilities (c) | $ | 9 |
| $ | 217 |
| $ | 226 |
| |
| 2016 | | | | | | | | |
| Fuel oils | | Other current assets | $ | 2 |
| $ | — |
| $ | 2 |
| |
| | | Other assets | | 1 |
| | — |
| | 1 |
| |
| Natural gas | Other current assets | $ | — |
| $ | 1 |
| $ | 1 |
| Other current assets | | 1 |
| | 11 |
| | 12 |
| |
| | Other assets | | 1 |
| | — |
| | 1 |
| Other assets | | 1 |
| | 2 |
| | 3 |
| |
| Power | Other current assets | | 16 |
| | — |
| | 16 |
| Other current assets | | 9 |
| | — |
| | 9 |
| |
| | Total assets (a) | $ | 17 |
| $ | 1 |
| $ | 18 |
| Total assets (a) | $ | 14 |
| $ | 13 |
| $ | 27 |
| |
| Fuel oils | Other current liabilities | $ | 22 |
| $ | — |
| $ | 22 |
| Other current liabilities | $ | 5 |
| $ | — |
| $ | 5 |
| |
| | Other deferred credits and liabilities | | 7 |
| | — |
| | 7 |
| |
| Natural gas | MTM derivative liabilities | | (b) |
| | 32 |
| | (b) |
| Other current liabilities | | 1 |
| | 3 |
| | 4 |
| |
| | Other current liabilities | | 6 |
| | — |
| | 38 |
| |
| | Other deferred credits and liabilities | | 8 |
| | 18 |
| | 26 |
| Other deferred credits and liabilities | | 5 |
| | 5 |
| | 10 |
| |
| Power | MTM derivative liabilities | | (b) |
| | 13 |
| | (b) |
| Other current liabilities | | 3 |
| | 12 |
| | 15 |
| |
| | Other current liabilities | | — |
| | — |
| | 13 |
| Other deferred credits and liabilities | | — |
| | 173 |
| | 173 |
| |
| | Other deferred credits and liabilities | | — |
| | 157 |
| | 157 |
| |
| Uranium | Other current liabilities | | 1 |
| | — |
| | 1 |
| Other deferred credits and liabilities | | 4 |
| | — |
| | 4 |
| |
| | Total liabilities (c) | $ | 44 |
| $ | 220 |
| $ | 264 |
| Total liabilities (c) | $ | 18 |
| $ | 193 |
| $ | 211 |
| |
| 2014 | | | | | | | |
| Fuel oils | Other current assets | $ | 2 |
| $ | — |
| $ | 2 |
| |
| Natural gas | Other current assets | | 1 |
| | 1 |
| | 2 |
| |
| Power | Other current assets | | 15 |
| | — |
| | 15 |
| |
| | Total assets (a) | $ | 18 |
| $ | 1 |
| $ | 19 |
| |
| Fuel oils | Other current liabilities | $ | 22 |
| $ | — |
| $ | 22 |
| |
| | Other deferred credits and liabilities | | 7 |
| | — |
| | 7 |
| |
| Natural gas | MTM derivative liabilities | | (b) |
| | 31 |
| | (b) |
| |
| | Other current liabilities | | 6 |
| | — |
| | 37 |
| |
| | Other deferred credits and liabilities | | 6 |
| | 13 |
| | 19 |
| |
| Power | MTM derivative liabilities | | (b) |
| | 11 |
| | (b) |
| |
| | Other current liabilities | | 3 |
| | — |
| | 14 |
| |
| | Other deferred credits and liabilities | | — |
| | 131 |
| | 131 |
| |
| Uranium | Other current liabilities | | 2 |
| | — |
| | 2 |
| |
| | Total liabilities (c) | $ | 46 |
| $ | 186 |
| $ | 232 |
| |
| |
| (a) | Because all contracts qualifying for hedge accounting receive regulatory deferral, theThe 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) | Because all contracts qualifying for hedge accounting receive regulatory deferral, theThe 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 andexchanges; these contracts have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master netting arrangements or similar agreements, and reporting daily exposure to senior management.
We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master netting arrangements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. 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 following table providesAmeren Companies elect to present the recognized gross derivative balances and the netfair value amounts of those derivativesderivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement as ofgross 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, 20152017 and 2014:2016.
|
| | | | | | | | | | | | |
| | | | | Gross Amounts Not Offset on the Balance Sheet | | |
| Commodity Contracts Eligible to be Offset | | Gross Amounts Recognized on the Balance Sheet | | Derivative Instruments | | Cash Collateral Received/Posted(a) | | Net Amount |
| 2015 | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | $ | 17 |
| $ | 1 |
| $ | — |
| $ | 16 |
|
| Ameren Illinois | | 1 |
| | — |
| | — |
| | 1 |
|
| Ameren | $ | 18 |
| $ | 1 |
| $ | — |
| $ | 17 |
|
| Liabilities: | | | | | | | | |
| Ameren Missouri | $ | 44 |
| $ | 1 |
| $ | 8 |
| $ | 35 |
|
| Ameren Illinois | | 220 |
| | — |
| | 3 |
| | 217 |
|
| Ameren | $ | 264 |
| $ | 1 |
| $ | 11 |
| $ | 252 |
|
| 2014 | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | $ | 18 |
| $ | 5 |
| $ | — |
| $ | 13 |
|
| Ameren Illinois | | 1 |
| | — |
| | — |
| | 1 |
|
| Ameren | $ | 19 |
| $ | 5 |
| $ | — |
| $ | 14 |
|
| Liabilities: | | | | | | | | |
| Ameren Missouri | $ | 46 |
| $ | 5 |
| $ | 5 |
| $ | 36 |
|
| Ameren Illinois | | 186 |
| | — |
| | — |
| | 186 |
|
| Ameren | $ | 232 |
| $ | 5 |
| $ | 5 |
| $ | 222 |
|
| |
(a)
| Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet. |
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. The potential loss on counterparty exposures may be reduced or eliminated by the application of master netting arrangements or similar agreements and collateral held. As of December 31, 2015,2017, if counterparty groups were to fail completely to perform on contracts, Ameren's,the Ameren Missouri's, and Ameren Illinois'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 we were to experience an adverse change in our credit ratings were downgraded, or if a counterparty with reasonable grounds for uncertainty regarding performance ofour ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2015,2017, 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, 2015,2017, 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) |
| 2015 | | | | | | |
| 2017 | | | | | | |
| Ameren Missouri | $ | 87 |
| | $ | 9 |
| | $ | 72 |
| $ | 55 |
| | $ | 3 |
| | $ | 44 |
|
| Ameren Illinois | 78 |
| | 3 |
| | 71 |
| 43 |
| | — |
| | 38 |
|
| Ameren | $ | 165 |
| | $ | 12 |
| | $ | 143 |
| $ | 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 exchange 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 11:: 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 recognizedindustry-recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed incomefixed-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 midpoints ofbid/ask spreads to the bid/ask spreads.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 midpoint.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 33:: 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, as wellsuch as certain internal assumptions.assumptions, quotes or prices from outside sources not supported by a liquid market, or escalation rates. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review,reviews and an evaluation of all sources is performed 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, 20152017 and 2014:2016:
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| | Level 3 Derivative asset and liability – commodity contracts(a): | | | |
| 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) |
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
Level 3 Derivative asset and liability – commodity contracts(a): | | | |
| 2017 | | | | | | | | |
| | Fuel oils | $ | 3 |
| $ | — |
| | Option model | Volatilities(%)(b) | 20 – 26 | 22 |
| | | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.12 – 0.72 | 0.41 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.37 | (e) |
| | Natural Gas | 1 |
| (4 | ) | | Option model | Volatilities(%)(b) | 26 – 46 | 37 |
| |
|
|
| |
| Nodal basis($/mmbtu)(c) | (0.50) – (0.30) | (0.40) |
| |
|
|
| | Discounted cash flow | Nodal basis($/mmbtu)(b) | (1.20) – 0.10 | (1) |
| |
|
|
| |
| Counterparty credit risk(%)(c)(d) | 0.37 – 0.92 | 0.53 |
| |
|
|
| |
| Ameren credit risk(%)(c)(d) | 0.37 | (e) |
| | Power(f) | 8 |
| (196 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 24 – 46 | 28 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (65) – 1,823 | 251 |
| | | | | | | Nodal basis($/MWh)(g) | (10) – 0 | (2) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.28 | (e) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.37 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| 2016 | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| | Option model | Volatilities(%)(b) | 24 – 66 | 28 |
| | | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.13 – 0.22 | 0.15 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | | | Escalation rate(%)(b)(i) | (2) – 2 | 0 |
| | Natural Gas | $ | 1 |
| $ | (1 | ) | | Option model | Volatilities(%)(b) | 31 – 66 | 36 |
| | | | | | | Nodal basis($/mmbtu)(b) | (0.40) – (0.10) | (0.20) |
| | | | | | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.80) – 0 | (0.50) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.13 – 8 | 1 |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | Power(f) | 9 |
| (187 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 26 – 44 | 29 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (71) – 5,270 | 125 |
| | | | | | | Nodal basis($/MWh)(g) | (6) – 0 | (2) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| | Uranium | — |
| (4 | ) | | Option model | Volatilities(%)(b) | 24 | (e) |
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| |
|
|
| |
| Counterparty credit risk(%)(c)(d) | 0.40 – 12 | 7 |
| |
|
|
| |
| Ameren Missouri credit risk(%)(c)(d) | 0.40 | (e) |
| | Power(f) | 16 |
| (170 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 22 – 39 | 29 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (270) – 2,057 | 211 |
| | | | | | | Nodal basis($/MWh)(g) | (10) – (1) | (3) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.86 | (e) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.40 | (e) |
| | | | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 3 – 4 | 4 |
| | | | | | | Escalation rate(%)(b)(h) | 3 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/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) |
| 2014 | | | | | | | | |
| | Fuel oils | $ | 2 |
| $ | (8 | ) | | Option model | Volatilities(%)(c) | 3 – 39 | 32 |
| | | | | | Discounted cash flow | Ameren Missouri credit risk(%)(c)(d) | 0.43 | (e) |
| | | | | | | Escalation rate(%)(b)(i) | 5 | (e) |
| | Natural Gas | 1 |
| (2 | ) | | Option model | Volatilities(%)(c) | 31 – 144 | 63 |
| | | | | | | Nodal basis($/mmbtu)(b) | (0.40) – 0 | (0.20) |
| | | | | | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.40) – 0.10 | (0.20) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.43 – 13 | 3 |
| | | | | | | Ameren Missouri and Ameren Illinois credit risk(%)(c)(d) | 0.43 | (e) |
| | Power(f) | 11 |
| (144 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 27 – 50 | 32 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (1,833) – 2,743 | 171 |
| | | | | | | Nodal basis($/MWh)(b) | (6) – 0 | (2) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.26 | (e) |
| | | | | | | Ameren Missouri and Ameren Illinois credit risk(%)(c)(d) | 0.43 | (e) |
| | | | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 – 5 | 4 |
| | | | | | | Escalation rate(%)(b)(h) | 0 – 1 | 1 |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| | Uranium | — |
| (2 | ) | | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 35 – 40 | 36 |
|
| | | | | | | | | | | | |
| | Fair Value | | | | | Weighted |
| | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| | | | | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 22 – 24 | 22 |
| | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) |
| |
| (a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
| (b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
| |
| (c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
| |
| (d) | Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances. |
| |
| (f) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2019.2021. Valuations beyond 20192021 use fundamentally modeled pricing by month for peak and off-peak demand. |
| |
| (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. |
| |
| (h) | Escalation rate applies to power prices 2026in 2031 and beyond. |
| |
| (i) | Escalation rate applies to fuel oil prices 2017in 2019 and beyond. |
In accordance with applicable authoritative accounting guidance, weWe 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 2015, 20142017, 2016, or 2013.2015. At December 31, 20152017 and 2014,2016, 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, 20152017:
| | | | | 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 | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Power | | — |
| | — |
| | 16 |
| | 16 |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Total derivative assets – commodity contracts | | $ | — |
| | $ | 1 |
| | $ | 17 |
| | $ | 18 |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
| | Cash and cash equivalents | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Equity securities: | | | | | | | | | | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | U.S. large capitalization | | 364 |
| | — |
| | — |
| | 364 |
| | Equity securities: | | | | | | | | | |
| | Debt securities: | | | | | | | | | | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | U.S. Treasury and agency securities | | — |
| | 109 |
| | — |
| | 109 |
| | Debt securities: | | | | | | | | | |
| | Corporate bonds | | — |
| | 58 |
| | — |
| | 58 |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Other | | — |
| | 22 |
| | — |
| | 22 |
| | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | Total nuclear decommissioning trust fund | | $ | 368 |
| | $ | 189 |
| | $ | — |
| | $ | 557 |
| (b) | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Total Ameren | | $ | 368 |
| | $ | 190 |
| | $ | 17 |
| | $ | 575 |
| | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | | Total Ameren | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Power | | — |
| | — |
| | 16 |
| | 16 |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Total derivative assets – commodity contracts | | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | 17 |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
| | Cash and cash equivalents | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | |
| | Equity securities: | | | | | | | | | | |
| | U.S. large capitalization | | 364 |
| | — |
| | — |
| | 364 |
| | |
| | Debt securities: | | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 109 |
| | — |
| | 109 |
| | |
| | Corporate bonds | | — |
| | 58 |
| | — |
| | 58 |
| | |
| | Other | | — |
| | 22 |
| | — |
| | 22 |
| | |
| | Total nuclear decommissioning trust fund | | $ | 368 |
| | $ | 189 |
| | $ | — |
| | $ | 557 |
| (b) | |
| | Total Ameren Missouri | | $ | 368 |
| | $ | 189 |
| | $ | 17 |
| | $ | 574 |
| | |
| Ameren Illinois | Derivative assets – commodity contracts(a): | | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | |
| Liabilities: | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | | |
| | Fuel oils | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | |
| | Natural gas | | 1 |
| | 62 |
| | 1 |
| | 64 |
| | |
| | Power | | — |
| | — |
| | 170 |
| | 170 |
| | |
| | Uranium | | — |
| | — |
| | 1 |
| | 1 |
| | |
| | Total Ameren | | $ | 30 |
| | $ | 62 |
| | $ | 172 |
| | $ | 264 |
| | |
| | | | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| | | Nuclear decommissioning trust fund: | | | | | | | | | |
| | | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | | Equity securities: | | | | | | | | | |
| | | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | | Debt securities: | | | | | | | | | |
| | | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | | Total Ameren Missouri | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Liabilities: | | | | | | | | | | |
| Ameren | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | 1 |
| | 25 |
| | 4 |
| | 30 |
| |
| | | | | | | | | | | | Power | | — |
| | — |
| | 196 |
| | 196 |
| |
| | | 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 | | Total Ameren | | $ | 1 |
| | $ | 25 |
| | $ | 200 |
| | $ | 226 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | Natural gas | | — |
| | 7 |
| | 1 |
| | 8 |
| |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| | Power | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | — |
| | — |
| | — |
| | Total Ameren Missouri | | $ | — |
| | $ | 7 |
| | $ | 2 |
| | $ | 9 |
| |
| | Uranium | | — |
| | — |
| | 1 |
| | 1 |
| | |
| | Total Ameren Missouri | | $ | 29 |
| | $ | 13 |
| | $ | 2 |
| | $ | 44 |
| | |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | 1 |
| | $ | 49 |
| | $ | — |
| | $ | 50 |
| | Natural gas | | $ | 1 |
| | $ | 18 |
| | $ | 3 |
| | $ | 22 |
| |
| | Power | | — |
| | — |
| | 170 |
| | 170 |
| | Power | | — |
| | — |
| | 195 |
| | 195 |
| |
| | Total Ameren Illinois | | $ | 1 |
| | $ | 49 |
| | $ | 170 |
| | $ | 220 |
| | Total Ameren Illinois | | $ | 1 |
| | $ | 18 |
| | $ | 198 |
| | $ | 217 |
| |
| |
| (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. |
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, 20142016:
| | | | | 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 |
| | $ | 2 |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Natural gas | | — |
| | 1 |
| | 1 |
| | 2 |
| | Natural gas | | 2 |
| | 12 |
| | 1 |
| | 15 |
| |
| | Power | | — |
| | 4 |
| | 11 |
| | 15 |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | — |
| | $ | 5 |
| | $ | 14 |
| | $ | 19 |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 12 |
| | $ | 11 |
| | $ | 27 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | |
| | Equity securities: | | | | | | | | | | |
| | U.S. large capitalization | | 364 |
| | — |
| | — |
| | 364 |
| | |
| | Debt securities: | | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 102 |
| | — |
| | 102 |
| | |
| | Corporate bonds | | — |
| | 63 |
| | — |
| | 63 |
| | |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| | |
| | Total nuclear decommissioning trust fund | | $ | 365 |
| | $ | 182 |
| | $ | — |
| | $ | 547 |
| (b) | |
| | Total Ameren | | $ | 365 |
| | $ | 187 |
| | $ | 14 |
| | $ | 566 |
| | |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | | |
| | Fuel oils | | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
| | |
| | Natural gas | | — |
| | 1 |
| | — |
| | 1 |
| | |
| | Power | | — |
| | 4 |
| | 11 |
| | 15 |
| | |
| | Total derivative assets – commodity contracts | | $ | — |
| | $ | 5 |
| | $ | 13 |
| | $ | 18 |
| | |
| | Nuclear decommissioning trust fund: | | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | |
| | Equity securities: | | | | | | | | | | |
| | U.S. large capitalization | | 364 |
| | — |
| | — |
| | 364 |
| | |
| | Debt securities: | | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 102 |
| | — |
| | 102 |
| | |
| | Corporate bonds | | — |
| | 63 |
| | — |
| | 63 |
| | |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| | |
| | Total nuclear decommissioning trust fund | | $ | 365 |
| | $ | 182 |
| | $ | — |
| | $ | 547 |
| (b) | |
| | Total Ameren Missouri | | $ | 365 |
| | $ | 187 |
| | $ | 13 |
| | $ | 565 |
| | |
| Ameren Illinois | Derivative assets – commodity contracts(a): | | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | |
| | | | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| | | Nuclear decommissioning trust fund: | | | | | | | | | |
| | | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | | Equity securities: | | | | | | | | | |
| | | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | | Debt securities: | | | | | | | | | |
| | | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | | Total Ameren | | $ | 413 |
| | $ | 208 |
| | $ | 11 |
| | $ | 632 |
| |
| Ameren Missouri | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | | Natural gas | | — |
| | 1 |
| | 1 |
| | 2 |
| |
| | | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | | Total derivative assets – commodity contracts | | $ | 2 |
| | $ | 1 |
| | $ | 11 |
| | $ | 14 |
| |
| | | Nuclear decommissioning trust fund: | | | | | | | | | |
| | | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | | Equity securities: | | | | | | | | | |
| | | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | | Debt securities: | | | | | | | | | |
| | | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | | Total Ameren Missouri | | $ | 411 |
| | $ | 197 |
| | $ | 11 |
| | $ | 619 |
| |
| Ameren Illinois | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | | 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 | | Natural gas | | $ | 2 |
| | $ | 11 |
| | $ | — |
| | $ | 13 |
| |
| Liabilities: | | | | | | | | | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 21 |
| | $ | — |
| | $ | 8 |
| | $ | 29 |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | 1 |
| | 53 |
| | 2 |
| | 56 |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| |
| | Power | | — |
| | 1 |
| | 144 |
| | 145 |
| | Power | | — |
| | 1 |
| | 187 |
| | 188 |
| |
| | Uranium | | — |
| | — |
| | 2 |
| | 2 |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren | | $ | 22 |
| | $ | 54 |
| | $ | 156 |
| | $ | 232 |
| | Total Ameren | | $ | 5 |
| | $ | 14 |
| | $ | 192 |
| | $ | 211 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 21 |
| | $ | — |
| | $ | 8 |
| | $ | 29 |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | 1 |
| | 10 |
| | 1 |
| | 12 |
| | Natural gas | | — |
| | 6 |
| | — |
| | 6 |
| |
| | Power | | — |
| | 1 |
| | 2 |
| | 3 |
| | Power | | — |
| | 1 |
| | 2 |
| | 3 |
| |
| | Uranium | | — |
| | — |
| | 2 |
| | 2 |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren Missouri | | $ | 22 |
| | $ | 11 |
| | $ | 13 |
| | $ | 46 |
| | Total Ameren Missouri | | $ | 5 |
| | $ | 7 |
| | $ | 6 |
| | $ | 18 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 43 |
| | $ | 1 |
| | $ | 44 |
| | Natural gas | | $ | — |
| | $ | 7 |
| | $ | 1 |
| | $ | 8 |
| |
| | Power | | — |
| | — |
| | 142 |
| | 142 |
| | Power | | — |
| | — |
| | 185 |
| | 185 |
| |
| | Total Ameren Illinois | | $ | — |
| | $ | 43 |
| | $ | 143 |
| | $ | 186 |
| | Total Ameren Illinois | | $ | — |
| | $ | 7 |
| | $ | 186 |
| | $ | 193 |
| |
| |
| (a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
| (b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
The following table summarizes the changes in the fair value ofAll costs related to financial assets and liabilities classified as Level 3 in the fair value hierarchy forare expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the yearfair value of these instruments. For the years ended December 31, 2015:2017 and 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.
|
| | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fuel oils: | | | | | | |
| Beginning balance at January 1, 2015 | $ | (6 | ) | $ | (a) |
| $ | (6 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities: | | (1 | ) | | (a) |
| | (1 | ) |
| Settlements | | 5 |
| | (a) |
| | 5 |
|
| Transfers out of Level 3 | | 2 |
| | (a) |
| | 2 |
|
| Ending balance at December 31, 2015 | $ | — |
| $ | (a) |
| $ | — |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2015 | $ | — |
| $ | (a) |
| $ | — |
|
| Natural gas: | | | | | | |
| Beginning balance at January 1, 2015 | $ | (1 | ) | $ | — |
| $ | (1 | ) |
Realized and unrealized gains (losses) included in regulatory assets/liabilities:
| | — |
| | 1 |
| | 1 |
|
| Settlements | | 1 |
| | (1 | ) | | — |
|
| Ending balance at December 31, 2015 | $ | — |
| $ | — |
| $ | — |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2015 | $ | — |
| $ | — |
| $ | — |
|
| Power: | | | | | | |
| 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 | ) |
| Uranium: | | | | | | |
| Beginning balance at January 1, 2015 | $ | (2 | ) | $ | (a) |
| $ | (2 | ) |
Realized and unrealized gains (losses) included in regulatory assets/liabilities:
| | (1 | ) | | (a) |
| | (1 | ) |
| Settlements | | 2 |
| | (a) |
| | 2 |
|
| Ending balance at December 31, 2015 | $ | (1 | ) | $ | (a) |
| $ | (1 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2015 | $ | — |
| $ | (a) |
| $ | — |
|
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 for the year ended December 31, 2014:hierarchy:
|
| | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fuel oils: | | | | | | |
| Beginning balance at January 1, 2014 | $ | 5 |
| $ | (a) |
| $ | 5 |
|
Realized and unrealized gains (losses) included in regulatory assets/liabilities:
| | (9 | ) | | (a) |
| | (9 | ) |
| Settlements | | (2 | ) | | (a) |
| | (2 | ) |
| Ending balance at December 31, 2014 | $ | (6 | ) | $ | (a) |
| $ | (6 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2014 | $ | (6 | ) | $ | (a) |
| $ | (6 | ) |
| Natural gas: | | | | | | |
| Beginning balance at January 1, 2014 | $ | — |
| $ | — |
| $ | — |
|
Realized and unrealized gains (losses) included in regulatory assets/liabilities:
| | — |
| | 1 |
| | 1 |
|
| Purchases | | — |
| | (2 | ) | | (2 | ) |
| Sales | | (1 | ) | | — |
| | (1 | ) |
| Settlements | | — |
| | 1 |
| | 1 |
|
| Ending balance at December 31, 2014 | $ | (1 | ) | $ | — |
| $ | (1 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2014 | $ | — |
| $ | 2 |
| $ | 2 |
|
| Power: | | | | | | |
| Beginning balance at January 1, 2014 | $ | 19 |
| $ | (108 | ) | $ | (89 | ) |
Realized and unrealized gains (losses) included in regulatory assets/liabilities:
| | (14 | ) | | (39 | ) | | (53 | ) |
| Purchases | | 34 |
| | — |
| | 34 |
|
| Sales | | (1 | ) | | — |
| | (1 | ) |
| Settlements | | (29 | ) | | 5 |
| | (24 | ) |
| Ending balance at December 31, 2014 | $ | 9 |
| $ | (142 | ) | $ | (133 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2014 | $ | — |
| $ | (43 | ) | $ | (43 | ) |
| Uranium: | | | | | | |
| Beginning balance at January 1, 2014 | $ | (6 | ) | $ | (a) |
| $ | (6 | ) |
Realized and unrealized gains (losses) included in regulatory assets/liabilities:
| | (1 | ) | | (a) |
| | (1 | ) |
| Settlements | | 5 |
| | (a) |
| | 5 |
|
| Ending balance at December 31, 2014 | $ | (2 | ) | $ | (a) |
| $ | (2 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2014 | $ | (1 | ) | $ | (a) |
| $ | (1 | ) |
|
| | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| For the year ended December 31, 2016 | | | | | | |
| Beginning balance at January 1, 2016 | $ | 16 |
| $ | (170 | ) | $ | (154 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | (1 | ) | | (29 | ) | | (30 | ) |
| Purchases | | 13 |
| | — |
| | 13 |
|
| Settlements | | (21 | ) | | 14 |
| | (7 | ) |
| Ending balance at December 31, 2016 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2016 | $ | — |
| $ | (27 | ) | $ | (27 | ) |
| For the year ended December 31, 2017 | | | | | | |
| Beginning balance at January 1, 2017 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | (4 | ) | | (21 | ) | | (25 | ) |
| Purchases | | 14 |
| | — |
| | 14 |
|
| Sales | | 1 |
| | — |
| | 1 |
|
| Settlements | | (11 | ) | | 11 |
| | — |
|
| Ending balance at December 31, 2017 | $ | 7 |
| $ | (195 | ) | $ | (188 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2017 | $ | — |
| $ | (22 | ) | $ | (22 | ) |
Transfers into or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level, but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3, but were recategorized to a higher level because the lowest significant input became observable during the period. TransfersFor the years ended December 31, 2017 and 2016, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, for fuel oils and betweenor Level 2 and Level 3 for power derivatives were primarily caused by changes in availability of similar financial trades observable on electronic exchanges between the periods. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.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, 20152017, as well as a table summarizing the changes in Level 3 plan assets during 20152017.
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, 20152017 and 20142016:
| | | | 2015 | | 2014 | 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)(b)(a) | $ | 7,275 |
| | $ | 7,814 |
| | $ | 6,205 |
| | $ | 7,135 |
| $ | 7,935 |
| | $ | 8,531 |
| | $ | 7,276 |
| | $ | 7,772 |
|
| Preferred stock | 142 |
| | 125 |
| | 142 |
| | 122 |
| |
Preferred stock(b) | | 142 |
| | 131 |
| | 142 |
| | 131 |
|
| Ameren Missouri: | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations (including current portion)(b)(a) | $ | 4,110 |
| | $ | 4,449 |
| | $ | 3,981 |
| | $ | 4,518 |
| $ | 3,961 |
| | $ | 4,348 |
| | $ | 3,994 |
| | $ | 4,304 |
|
| Preferred stock | 80 |
| | 75 |
| | 80 |
| | 73 |
| 80 |
| | 80 |
| | 80 |
| | 79 |
|
| Ameren Illinois: | | | | | | | | | | | | | | |
Long-term debt (including current portion)(b) | $ | 2,471 |
| | $ | 2,665 |
| | $ | 2,224 |
| | $ | 2,517 |
| $ | 2,830 |
| | $ | 3,028 |
| | $ | 2,588 |
| | $ | 2,765 |
|
| Preferred stock | 62 |
| | 50 |
| | 62 |
| | 49 |
| 62 |
| | 51 |
| | 62 |
| | 52 |
|
| |
| (a) | Preferred stock isAmeren 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 "Noncontrolling Interests" on“Other Assets” that are related to the consolidated balance sheet.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) | Carrying amounts reflectPreferred stock is recorded in “Noncontrolling Interests” on the adoption of the new authoritative accounting guidance for the presentation of debt issuance costs. See Note 1 – Summary of Significant Accounting Policiesconsolidated 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, 2015, and 2014. 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, 2015, 2014, and 2013:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Proceeds from sales and maturities | $ | 349 |
| | $ | 391 |
| | $ | 196 |
|
| Gross realized gains | 8 |
| | 7 |
| | 7 |
|
| Gross realized losses | 2 |
| | 2 |
| | 5 |
|
Net realized and unrealized gains and losses are deferred and recorded as a regulatory asset or a regulatory liability 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, 2015 and 2014:
|
| | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 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 |
|
| 2014 | | | | | | | |
| Debt securities | $ | 175 |
| | $ | 7 |
| $ | — |
| | $ | 182 |
|
| Equity securities | 138 |
| | 230 |
| | 4 |
| | 364 |
|
| Cash | 1 |
| | — |
| | — |
| | 1 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 316 |
| | $ | 237 |
| $ | 4 |
| | $ | 549 |
|
| |
(a) | Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest. |
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, 2015:
|
| | | | | | | |
| | Cost | | Fair Value |
| Less than 5 years | $ | 106 |
| | $ | 105 |
|
| 5 years to 10 years | 42 |
| | 41 |
|
| Due after 10 years | 43 |
| | 43 |
|
| Total | $ | 191 |
| | $ | 189 |
|
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. Ameren Missouri received a license extension from the NRC in March 2015 to extend the Callaway energy center’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in Ameren's and Ameren Missouri's nuclear decommissioning trust fund. They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position at December 31, 2015:
|
| | | | | | | | | | | | | | | | | | | | | |
| | Less than 12 Months | | | 12 Months or Greater | | Total |
| | Fair Value | | Gross Unrealized Losses | | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| Debt securities | $ | 136 |
| $ | 3 |
| | | $ | 4 |
| $ | 1 |
| | $ | 140 |
| $ | 4 |
|
| Equity securities | 16 |
| | 3 |
| | | 4 |
| | 4 |
| | 20 |
| | 7 |
|
| Total | $ | 152 |
| $ | 6 |
| | | $ | 8 |
| $ | 5 |
| | $ | 160 |
| $ | 11 |
|
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. Under the NWPA, Ameren Missouri and other owners of nuclear energy centers are responsible for paying the disposal costs. The NWPA established the fee paid by Ameren Missouri and other utilities that these utilities payown and operate those energy centers to 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 is currently suspended.
Although both the NWPA and the standard contract stated that the DOE would begin to dispose of spent nuclear fuel by 1998, the DOE is not meeting its disposal obligation.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. Ameren Missouri has sufficient capacity in the spent fuel pool and dry spent storage facility at the Callaway energy center to store its spent nuclear fuel generated through the end of the energy center’s operating license in 2044.
As a result of the DOE'sDOE’s failure to begin to dispose of spent nuclear fuel from commercial nuclear energy centers and fulfill its
contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs such as certain NRC fees and Missouri ad valorem taxes, incurred for ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual recoveryreimbursement of additional spent fuel storage and related costs incurred from 2010 through 2016, with the ability to extend the recovery period as mutually agreed upon by the parties. Included in these reimbursements are costs related to the dry spent fuel storage facility at the Callaway energy center, to whichcosts. Ameren Missouri began transferring spent fuel assembliesreceived reimbursements from the DOE of $3 million, $24 million, and $14 million in 2015.2017, 2016, and 2015, respectively. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.
Supplier 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. Following the NRC’s decision in March 2015 to extend the Callaway energy center’s operating license from 2024 to 2044, anAn updated cost study and a revised funding analysis werewas filed
with the MoPSC in April 2015. Ameren Missouri’s April 2015 filing supportedSeptember 2017 and reflected within the ARO. In January 2018, the MoPSC approved no change in electric service rates for decommissioning costs. There is no time requirement by which the MoPSC must issue an order regarding the decommissioning cost included incosts based on Ameren Missouri’s electric service rates. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. 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 information relatedclaims 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.
If 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 offershas defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren offershas 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 plans areplan is the Ameren Retiree Medical PlanWelfare 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.
In December 2013, Ameren completed the divestiture of New AER to IPH. In accordance with the transaction agreement, Ameren retained the pension obligations as of December 2, 2013, associated with the current and former employees of New AER and its subsidiaries who were included in the Ameren Retirement Plan and the Ameren Supplemental Retirement Plan. Ameren also retained the postretirement benefit obligations associated with the employees of New AER and its subsidiaries who were eligible to retire at December 2, 2013, and who were included in the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan.
Ameren’s unfunded obligation under its pension and other postretirement benefit plans was $567$551 million and $710$774 million as of December 31, 20152017, and December 31, 2014,2016, 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 decrease in the unfunded obligation during 20152017 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 increasedecrease in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligation. The decrease in the unfunded obligation also resulted in a decrease to "Regulatory assets"“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, 20152017 and 20142016:
| | | | 2015 |
| 2014 |
| 2017 |
| 2016 |
|
Ameren(a) | $ | 567 |
| $ | 710 |
| $ | 551 |
| $ | 774 |
|
| Ameren Missouri | 236 |
| 277 |
| 215 |
| 293 |
|
Ameren Illinois | 219 |
| 278 |
| 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, in accordance with authoritative accounting guidance.assets. The following table presents the funded status of Ameren'sAmeren’s pension and postretirement benefit plans as of December 31, 20152017 and 20142016. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 20152017 and 20142016, that have not been recognized in net periodic benefit costs.
| | | | 2015 | | 2014 | 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 | $ | 3,995 |
| $ | (b) |
| | $ | 4,176 |
| $ | (b) |
| $ | 4,577 |
| $ | (b) |
| | $ | 4,288 |
| $ | (b) |
|
| Change in benefit obligation: | | | | | | | | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,410 |
| $ | 1,203 |
| | $ | 3,900 |
| $ | 1,096 |
| $ | 4,518 |
| $ | 1,170 |
| | $ | 4,197 |
| $ | 1,094 |
|
| Service cost | 92 |
| | 24 |
| | 79 |
| | 19 |
| 93 |
| | 21 |
| | 81 |
| | 19 |
|
| Interest cost | 174 |
| | 48 |
| | 183 |
| | 50 |
| 179 |
| | 47 |
| | 185 |
| | 50 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 16 |
| — |
| | 8 |
| | — |
| | 8 |
|
| Actuarial (gain) loss | (256 | ) | | (133 | ) | | 462 |
| | 84 |
| |
| Settlement | (2 | ) | | — |
| | — |
| | — |
| |
| Actuarial loss | | 255 |
| | 53 |
| | 265 |
| | 52 |
|
| Benefits paid | (221 | ) | | (56 | ) | | (214 | ) | | (65 | ) | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Federal subsidy on benefits paid | (b) |
| | — |
| | (b) |
| | 3 |
| (b) |
| | — |
| | (b) |
| | 1 |
|
| Net benefit obligation at end of year | 4,197 |
| | 1,094 |
| | 4,410 |
| | 1,203 |
| 4,827 |
| | 1,240 |
| | 4,518 |
| | 1,170 |
|
| Change in plan assets: | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | 3,794 |
| | 1,109 |
| | 3,461 |
| | 1,074 |
| 3,813 |
| | 1,101 |
| | 3,653 |
| | 1,071 |
|
| Actual return on plan assets | (29 | ) | | (8 | ) | | 448 |
| | 75 |
| 634 |
| | 171 |
| | 313 |
| | 73 |
|
| Employer contributions | 111 |
| | 18 |
| | 99 |
| | 6 |
| 64 |
| | 2 |
| | 57 |
| | 2 |
|
| Federal subsidy on benefits paid | (b) |
| | — |
| | (b) |
| | 3 |
| (b) |
| | — |
| | (b) |
| | 1 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 16 |
| — |
| | 8 |
| | — |
| | 8 |
|
| Settlements | (2 | ) | | — |
| | — |
| | — |
| |
| Benefits paid | (221 | ) | | (56 | ) | | (214 | ) | | (65 | ) | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Fair value of plan assets at end of year | 3,653 |
| | 1,071 |
| | 3,794 |
| | 1,109 |
| 4,293 |
| | 1,223 |
| | 3,813 |
| | 1,101 |
|
| Funded status – deficiency | 544 |
| | 23 |
| | 616 |
| | 94 |
| 534 |
| | 17 |
| | 705 |
| | 69 |
|
| Accrued benefit cost at December 31 | $ | 544 |
| $ | 23 |
| | $ | 616 |
| $ | 94 |
| $ | 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 | 541 |
| | 39 |
| | 613 |
| | 92 |
| 531 |
| | 14 |
| | 702 |
| | 67 |
|
| Net liability recognized | $ | 544 |
| $ | 23 |
| | $ | 616 |
| $ | 94 |
| $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in regulatory assets consist of: | | | | | | | | | | | | | | |
| Net actuarial (gain) loss | $ | 395 |
| $ | (82 | ) | | $ | 452 |
| $ | (7 | ) | $ | 374 |
| $ | (69 | ) | | $ | 535 |
| $ | (29 | ) |
| Prior service cost (credit) | (5 | ) | | (11 | ) | | (6 | ) | | (16 | ) | |
| Prior service credit | | (3 | ) | | (3 | ) | | (4 | ) | | (8 | ) |
| Amounts (pretax) recognized in accumulated OCI consist of: | | | | | | | | | | | | | | |
| Net actuarial (gain) loss | 17 |
| | (3 | ) | | 29 |
| | (5 | ) | |
| Prior service cost (credit) | — |
| | — |
| | — |
| | (1 | ) | |
| Net actuarial loss | | 30 |
| | 2 |
| | 43 |
| | — |
|
| Prior service credit | | — |
| | — |
| | — |
| | (1 | ) |
| Total | $ | 407 |
| $ | (96 | ) | | $ | 475 |
| $ | (29 | ) | $ | 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, 20152017 and 20142016:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2016 | | 2017 | | 2016 |
| Discount rate at measurement date | 4.50 | % | | 4.00 | % | | 4.50 | % | | 4.00 | % | 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 |
|
| Years to ultimate rate | (a) |
| | (a) |
| | — |
| | — |
| |
| |
| (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 2015,2017, Ameren adopted the Society of Actuaries 2015 Mortality Tables Report and2017 Mortality Improvement Scale. The updated mortality tables assumescale assumes a lower rate of mortality improvement as compared to the 2014 Mortality Tables Report and2016 Mortality Improvement Scale that Ameren adopted
used in 2014. The 2015 tables lowered projected improvements in life expectancies for our employees and retirees,2016, 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 expensecost or the legally required minimum contribution. Considering its assumptions at December 31, 20152017, its investment performance in 2015,2017, and its pension funding policy, Ameren expects to make annual contributions of less than $401 million to $7060 million in each of the next five years, with aggregate estimated contributions of $280120 million. We expect Ameren Missouri’sMissouri and Ameren Illinois’Illinois expect their portion of the future funding requirements to be 40%35% and 50%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 20152017, 20142016, and 20132015:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 47 |
| | $ | 41 |
| | $ | 60 |
| | $ | 8 |
| | $ | 3 |
| | $ | 10 |
| $ | 19 |
| | $ | 21 |
| | $ | 47 |
| | $ | 1 |
| | $ | 1 |
| | $ | 8 |
|
| Ameren Illinois | 45 |
| | 39 |
| | 50 |
| | 8 |
| | 2 |
| | 11 |
| 37 |
| | 30 |
| | 45 |
| | 1 |
| | 1 |
| | 8 |
|
| Other | 19 |
| | 19 |
| | 46 |
| | 2 |
| | 1 |
| | 4 |
| 8 |
| | 6 |
| | 19 |
| | — |
| | — |
| | 2 |
|
Ameren(a) | 111 |
| | 99 |
| | 156 |
| | 18 |
| | 6 |
| | 25 |
| 64 |
| | 57 |
| | 111 |
| | 2 |
| | 2 |
| | 18 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
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 2016.2018. No plan assets are expected to be returned to Ameren during 2016.2018.
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 20162018 and our pension and postretirement plans’ asset categories as of December 31, 20152017 and 20142016:
| | Asset Category | Target Allocation 2016 | | Percentage of Plan Assets at December 31, | Target Allocation 2018 | | Percentage of Plan Assets at December 31, |
| 2015 | | 2014 | 2017 | | 2016 |
| Pension Plan: | | | | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 2 | % | 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% | | 7 | % | | 7 | % | 3% – 13% | | 9 | % | | 9 | % |
| International and emerging markets | 9% – 19% | | 13 | % | | 12 | % | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 51% – 61% | | 54 | % | | 53 | % | 51% – 61% | | 57 | % | | 57 | % |
| Debt securities | 35% – 45% | | 40 | % | | 41 | % | 35% – 45% | | 37 | % | | 37 | % |
| Real estate | 0% – 9% | | 5 | % | | 4 | % | 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% | | 4 | % | | 4 | % | 0% – 7% | | 2 | % | | 3 | % |
| Equity securities: | | | | | | | | |
| U.S. large-capitalization | 34% – 44% | | 39 | % | | 40 | % | 34% – 44% | | 41 | % | | 40 | % |
| U.S. small- and mid-capitalization | 2% – 12% | | 7 | % | | 7 | % | 2% – 12% | | 8 | % | | 7 | % |
| International | 9% – 19% | | 13 | % | | 13 | % | |
| International and emerging markets | | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 55% – 65% | | 59 | % | | 60 | % | 55% – 65% | | 63 | % | | 61 | % |
| Debt securities | 33% – 43% | | 37 | % | | 36 | % | 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. Ameren’s investment in private equity funds is spread among eight different limited partnerships, with invested capital ranging from less than $1 million to $4 million in each, which invest primarily in a diversified number of small United States-based companies. Ameren is seeking to eliminate its private equity investments over time. 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, 20152017. 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 net asset valuationNAV as a practical expedient are based on the fair values of the underlying assets provided by the funds and their administrators. The fair value of real estate investments is based on NAV; it is determined by annual appraisal reports prepared by an independent real estate appraiser. Investments measured at NAV often provide for daily, monthly, or quarterly redemptions with 60 or less days of notice depending on the fund. For some funds, redemption may also require approval from the fund’s board of directors. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information. The fair value of real estate is based on annual appraisal reports prepared by an independent real estate appraiser.
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, 20152017:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | 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 | $ | — |
| | $ | 20 |
| | $ | — |
| | $ | 20 |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | 25 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — |
| | 1,296 |
| | — |
| | 1,296 |
| — |
| | — |
| | — |
| | 1,523 |
| | 1,523 |
|
| U.S. small- and mid-capitalization | 268 |
| | — |
| | — |
| | 268 |
| 379 |
| | — |
| | — |
| | — |
| | 379 |
|
| International and emerging markets | 122 |
| | 369 |
| | — |
| | 491 |
| 179 |
| | — |
| | — |
| | 450 |
| | 629 |
|
| Debt securities: | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 631 |
| | — |
| | 631 |
| — |
| | 726 |
| | — |
| | 15 |
| | 741 |
|
| Municipal bonds | — |
| | 104 |
| | — |
| | 104 |
| — |
| | 91 |
| | — |
| | — |
| | 91 |
|
| U.S. Treasury and agency securities | 6 |
| | 751 |
| | — |
| | 757 |
| 8 |
| | 816 |
| | — |
| | — |
| | 824 |
|
| Other | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Real estate | — |
| | — |
| | 168 |
| | 168 |
| — |
| | — |
| | — |
| | 196 |
| | 196 |
|
| Private equity | — |
| | — |
| | 8 |
| | 8 |
| — |
| | — |
| | — |
| | 4 |
| | 4 |
|
| Total | $ | 396 |
| | $ | 3,176 |
| | $ | 176 |
| | $ | 3,748 |
| $ | 566 |
| | $ | 1,640 |
| | $ | — |
| | $ | 2,213 |
| | $ | 4,419 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | (123 | ) | | | | | | | | | (153 | ) |
Plus: Net receivables at December 31(b) | | | | | | | 28 |
| | | | | | | | | 27 |
|
| Fair value of pension plans assets at year end | | | | | | | $ | 3,653 |
| |
| Fair value of pension plans’ assets at December 31 | | | | | | | | | | $ | 4,293 |
|
| |
| (a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. |
| |
| (b) | Receivables related to pending 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, 20142016:
| | | | Quoted Prices in Active Markets for Identified Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | 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 | $ | — |
| | $ | 38 |
| | $ | — |
| | $ | 38 |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — |
| | 1,331 |
| | — |
| | 1,331 |
| — |
| | — |
| | — |
| | 1,352 |
| | 1,352 |
|
| U.S. small- and mid-capitalization | 270 |
| | — |
| | — |
| | 270 |
| 361 |
| | — |
| | — |
| | — |
| | 361 |
|
| International and emerging markets | 134 |
| | 360 |
| | — |
| | 494 |
| 133 |
| | — |
| | — |
| | 389 |
| | 522 |
|
| Debt securities: | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 1,026 |
| | — |
| | 1,026 |
| — |
| | 617 |
| | — |
| | 13 |
| | 630 |
|
| Municipal bonds | — |
| | 175 |
| | — |
| | 175 |
| — |
| | 95 |
| | — |
| | — |
| | 95 |
|
| U.S. Treasury and agency securities | 6 |
| | 366 |
| | — |
| | 372 |
| — |
| | 701 |
| | — |
| | — |
| | 701 |
|
| Other | — |
| | 31 |
| | — |
| | 31 |
| — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Real estate | — |
| | — |
| | 147 |
| | 147 |
| — |
| | — |
| | — |
| | 202 |
| | 202 |
|
| Private equity | — |
| | — |
| | 13 |
| | 13 |
| — |
| | — |
| | — |
| | 6 |
| | 6 |
|
| Derivative assets | 1 |
| | — |
| | — |
| | 1 |
| |
| Total | $ | 411 |
| | $ | 3,327 |
| | $ | 160 |
| | $ | 3,898 |
| $ | 494 |
| | $ | 1,434 |
| | $ | — |
| | $ | 1,995 |
| | $ | 3,923 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | (125 | ) | | | | | | | | | (132 | ) |
Plus: Net receivables at December 31(b) | | | | | | | 21 |
| | | | | | | | | 22 |
|
| Fair value of pension plans assets at year end | | | | | | | $ | 3,794 |
| |
| Fair value of pension plans’ assets at December 31 | | | �� | | | | | | | $ | 3,813 |
|
| |
| (a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. |
| |
| (b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair value hierarchy for each of the years ended December 31, 2015 and 2014:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Beginning Balance at January 1, | | Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date | | Actual Return on Plan Assets Related to Assets Sold During the Period | | Purchases, Sales, and Settlements, Net | | Net Transfers into (out of) of Level 3 | | Ending Balance at December 31, |
| 2015: | | | | | | | | | | | |
| Real estate | $ | 147 |
| | $ | 14 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 168 |
|
| Private equity | 13 |
| | (9 | ) | | 9 |
| | (5 | ) | | — |
| | 8 |
|
| 2014: | | | | | | | | | | | |
| Real estate | $ | 131 |
| | $ | 11 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 147 |
|
| Private equity | 15 |
| | (9 | ) | | 10 |
| | (3 | ) | | — |
| | 13 |
|
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, 20152017:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | 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 |
| $ | 44 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 44 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 272 |
| | 98 |
| | — |
| | 370 |
| 332 |
| | — |
| | — |
| | 110 |
| | 442 |
|
| U.S. small- and mid-capitalization | 65 |
| | — |
| | — |
| | 65 |
| 80 |
| | — |
| | — |
| | — |
| | 80 |
|
| International | 33 |
| | 93 |
| | — |
| | 126 |
| |
| International and emerging markets | | 53 |
| | — |
| | — |
| | 101 |
| | 154 |
|
| Other | — |
| | 7 |
| | — |
| | 7 |
| — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Debt securities: | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 138 |
| | — |
| | 138 |
| — |
| | 144 |
| | — |
| | — |
| | 144 |
|
| Municipal bonds | — |
| | 114 |
| | — |
| | 114 |
| — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 55 |
| | — |
| | 55 |
| — |
| | 76 |
| | — |
| | — |
| | 76 |
|
| Other | — |
| | 40 |
| | — |
| | 40 |
| — |
| | 4 |
| | — |
| | 34 |
| | 38 |
|
| Total | $ | 431 |
| | $ | 545 |
| | $ | — |
| | $ | 976 |
| $ | 509 |
| | $ | 342 |
| | $ | — |
| | $ | 245 |
| | $ | 1,096 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | 123 |
| | | | | | | | | 153 |
|
Less: Net payables at December 31(b) | | | | | | | (28 | ) | | | | | | | | | (26 | ) |
| Fair value of postretirement benefit plans assets at year end | | | | | | | $ | 1,071 |
| |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | | $ | 1,223 |
|
| |
| (a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
| (b) | Payables related to pending 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, 20142016:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | 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 | $ | 89 |
| | $ | — |
| | $ | — |
| | $ | 89 |
| $ | 53 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 291 |
| | 101 |
| | — |
| | 392 |
| 291 |
| | — |
| | — |
| | 101 |
| | 392 |
|
| U.S. small- and mid-capitalization | 70 |
| | — |
| | — |
| | 70 |
| 72 |
| | — |
| | — |
| | — |
| | 72 |
|
| International | 37 |
| | 94 |
| | — |
| | 131 |
| |
| International and emerging markets | | 40 |
| | — |
| | — |
| | 92 |
| | 132 |
|
| Other | — |
| | 7 |
| | — |
| | 7 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Debt securities: | | | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 105 |
| | — |
| | 105 |
| — |
| | 141 |
| | — |
| | — |
| | 141 |
|
| Municipal bonds | — |
| | 111 |
| | — |
| | 111 |
| — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 89 |
| | — |
| | 89 |
| — |
| | 68 |
| | — |
| | — |
| | 68 |
|
| Other | — |
| | 44 |
| | — |
| | 44 |
| — |
| | — |
| | — |
| | 19 |
| | 19 |
|
| Total | $ | 487 |
| | $ | 551 |
| | $ | — |
| | $ | 1,038 |
| $ | 456 |
| | $ | 326 |
| | $ | — |
| | $ | 212 |
| | $ | 994 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | 125 |
| | | | | | | | | 132 |
|
Less: Net payables at December 31(b) | | | | | | | (54 | ) | | | | | | | | | (25 | ) |
| Fair value of postretirement benefit plans assets at year end | | | | | | | $ | 1,109 |
| |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | | $ | 1,101 |
|
| |
| (a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
| (b) | Payables related to pending security purchases, offset by 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 20152017, 20142016, and 20132015:
| | | | Pension Benefits(a) | | Postretirement Benefits(a) | 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 |
|
| Interest cost | | 185 |
| | 50 |
|
| Expected return on plan assets | | (253 | ) | | (72 | ) |
| Amortization of: | | | | |
| Prior service credit | | (1 | ) | | (5 | ) |
| Actuarial (gain) loss | | 32 |
| | (11 | ) |
| Net periodic benefit cost (income) | | $ | 44 |
| | $ | (19 | ) |
| 2015 | | | | | | |
| Service cost | $ | 92 |
| | $ | 24 |
| $ | 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 |
| | — |
| |
| Curtailment gain | | 1 |
| | — |
|
| Net periodic benefit cost | $ | 92 |
| | $ | 4 |
| $ | 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 | ) | |
| 2013 | | | | |
| Service cost | $ | 91 |
| | $ | 22 |
| |
| Interest cost | 163 |
| | 46 |
| |
| Expected return on plan assets | (218 | ) | | (62 | ) | |
| Amortization of: | | | | |
| Prior service credit | (2 | ) | | (6 | ) | |
| Actuarial loss | 87 |
| | 8 |
| |
| Curtailment gain | (12 | ) | | (7 | ) | |
Net periodic benefit cost(b) | $ | 109 |
| | $ | 1 |
| |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(b) | The net periodic benefit cost includes a $6 million and a $7 million net gain for pension benefits and postretirement benefits, respectively, which was included in "Income (loss) from discontinued operations, net of taxes" on Ameren's consolidated statement of income (loss). This net gain includes the curtailment gain recognized in 2013 as a result of a significant reduction in employees as of the December 2, 2013 closing date of the New AER divestiture. See Note 16 – Divestiture Transactions and Discontinued Operations for additional information on the divestiture.
|
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into Ameren'sAmeren’s net periodic benefit cost in 20162018 are as follows:
| | | Pension Benefits(a) | | Postretirement Benefits(a) | Pension Benefits(a) | | Postretirement Benefits(a) |
| Regulatory assets: | | | | | | |
| Prior service credit | $ | (1 | ) | | $ | (4 | ) | $ | (1 | ) | | $ | (2 | ) |
| Net actuarial (gain) loss | | 60 |
| | (1 | ) |
| Accumulated OCI: | | | | |
| Net actuarial loss | 46 |
| | (3 | ) | 5 |
| | — |
|
| Accumulated OCI: | | | | |
| Net actuarial (gain) loss | (3 | ) | | (2 | ) | |
| Total | $ | 42 |
| | $ | (9 | ) | $ | 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. The netNet actuarial (gain) lossgains or losses subject to amortization isare 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, 20152017, 20142016, and 20132015:
| | | | Pension Costs | | Postretirement Costs | Pension Costs | | Postretirement Costs |
| | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Ameren Missouri(a) | $ | 54 |
| | $ | 50 |
| | $ | 69 |
| | $ | 8 |
| | $ | 3 |
| | $ | 8 |
| $ | 24 |
| | $ | 26 |
| | $ | 54 |
| | $ | (4 | ) | | $ | (5 | ) | | $ | 8 |
|
| Ameren Illinois | 38 |
| | 30 |
| | 41 |
| | (3 | ) | | (9 | ) | | — |
| 41 |
| | 22 |
| | 38 |
| | (14 | ) | | (13 | ) | | (3 | ) |
| Other | — |
| | 1 |
| | 5 |
| | (1 | ) | | (2 | ) | | — |
| (1 | ) | | (4 | ) | | — |
| | — |
| | (1 | ) | | (1 | ) |
Ameren(b) | 92 |
| | 81 |
| | 115 |
| | 4 |
| | (8 | ) | | 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. |
| |
(b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
The expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, as of December 31, 20152017, 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 |
| 2016 | $ | 233 |
| | $ | 3 |
| | $ | 55 |
| | $ | 2 |
| |
| 2017 | 244 |
| | 3 |
| | 58 |
| | 2 |
| |
| 2018 | 250 |
| | 3 |
| | 60 |
| | 2 |
| $ | 255 |
| | $ | 3 |
| | $ | 57 |
| | $ | 2 |
|
| 2019 | 257 |
| | 3 |
| | 62 |
| | 2 |
| 261 |
| | 3 |
| | 59 |
| | 2 |
|
| 2020 | 261 |
| | 3 |
| | 65 |
| | 2 |
| 266 |
| | 3 |
| | 62 |
| | 2 |
|
2021 – 2025 | 1,377 |
| | 13 |
| | 341 |
| | 12 |
| |
| 2021 | | 277 |
| | 3 |
| | 64 |
| | 2 |
|
| 2022 | | 280 |
| | 3 |
| | 65 |
| | 2 |
|
2023 – 2027 | | 1,421 |
| | 13 |
| | 331 |
| | 12 |
|
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 20152017, 20142016, and 20132015:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount rate at measurement date | 4.00 | % | | 4.75 | % | | 4.00 | % | | 4.00 | % | | 4.75 | % | | 4.00 | % | 4.00 | % | | 4.50 | % | | 4.00 | % | | 4.00 | % | | 4.50 | % | | 4.00 | % |
| Expected return on plan assets | 7.25 |
| | 7.25 |
| | 7.50 |
| | 7.00 |
| | 7.00 |
| | 7.25 |
| 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 |
|
| Years to ultimate rate | (a) |
| | (a) |
| | (a) |
| | — |
| | — |
| | — |
| |
| |
| (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 | ) | | $ | 130 |
| | $ | 1 |
| | $ | 37 |
| $ | (1 | ) | | $ | 157 |
| | $ | — |
| | $ | 44 |
|
| 0.25% increase in salary scale | 2 |
| | 14 |
| | — |
| | — |
| 2 |
| | 15 |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | 3 |
| | 44 |
| — |
| | — |
| | 4 |
| | 71 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | (3 | ) | | (44 | ) | — |
| | — |
| | (4 | ) | | (71 | ) |
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees at December 31, 20152017. 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, 20152017, 20142016, and 20132015:
| | | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 16 |
| | $ | 16 |
| | $ | 16 |
| $ | 16 |
| | $ | 16 |
| | $ | 16 |
|
| Ameren Illinois | 12 |
| | 11 |
| | 10 |
| 13 |
| | 12 |
| | 12 |
|
| Other | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
Ameren(a) | 29 |
| | 28 |
| | 27 |
| 30 |
| | 29 |
| | 29 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
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. To the extent that the issuance of a share that is subject to an outstanding award under the 2006 Incentive Plan would cause Ameren to exceed the maximum authorizedAt December 31, 2017, there were 4.9 million common shares under the 2006 Incentive Plan, the issuance of that share will take place under the 2014 Incentive Plan. This will reduce the maximum number of shares that may be grantedremaining 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 summary of nonvested shares at December 31, 2015, and changes during the year ended December 31, 2015, 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, 2015 | 1,162,377 |
| | $ | 35.35 |
|
Granted(a) | 570,313 |
| | 52.88 |
|
| Forfeitures | (1,944 | ) | | 34.75 |
|
Earned and vested(b) | (705,876 | ) | | 33.93 |
|
| Nonvested at December 31, 2015 | 1,024,870 |
| | $ | 46.08 |
|
| |
(a) | Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2015 under the 2014 Incentive Plan. |
| |
(b) | Includes share units granted in 2013 that vested as of December 31, 2015, that were earned pursuant to the terms of the award grants. Also includes 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.
|
Ameren recorded compensation expense of $19 million, $19 million, and $20 million for the years ended December 31, 2015, 2014, and 2013, respectively, and a related tax benefit of $7 million, $7 million, and $8 million for the years ended December 31, 2015, 2014, and 2013, respectively. Ameren settled performance share units of $27 million, $33 million, and $11 million for the years ended December 31, 2015, 2014, and 2013. There were no significant compensation costs capitalized related to the performance share units during the years ended December 31, 2015, 2014, and 2013. As of December 31, 2015, total compensation cost of $21 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 23 months.
Performance Share Units
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-yearthree-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 extendedextends beyond the three-year performance period to the payout date, whiledate.
The following table summarizes the vesting periodnonvested performance share unit activity for the year ended December 31, 2017:
|
| | | | | | |
| | Performance Share Units |
| | Share Units | | Weighted-average Grant Date Fair Value per Share Unit |
Nonvested at January 1, 2017(a) | 780,545 |
| | $ | 47.54 |
|
Granted(b) | 508,161 |
| | 59.16 |
|
| Forfeitures | (50,523 | ) | | 52.50 |
|
Undistributed vested units(c) | (342,694 | ) | | 51.65 |
|
Nonvested at December 31, 2017(a) | 895,489 |
| | $ | 52.28 |
|
| |
| (a) | Excludes 369,878 and 712,572 performance share units granted to retirement-eligible employees as of January 1, 2017 and December 31, 2017, respectively, as the undistributed performance share units are fully vested. |
| |
| (b) | Includes performance share units granted to certain executive and nonexecutive officers and other eligible employees in 2017 under the 2014 Incentive Plan. |
| |
| (c) | Includes performance share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period. |
The following table presents the stock-based compensation expense for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 4 |
| | $ | 4 |
| | $ | 5 |
|
| Ameren Illinois | 2 |
| | 2 |
| | 3 |
|
Other(a) | 12 |
| | 11 |
| | 11 |
|
| Ameren | 18 |
| | 17 |
| | 19 |
|
| Less income tax benefit | 7 |
| | 6 |
| | 7 |
|
| Stock-based compensation expense, net | $ | 11 |
| | $ | 11 |
| | $ | 12 |
|
| |
| (a) | Represents compensation expense of employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above. |
Ameren settled performance share units awarded in 2013of $39 million, $83 million, and 2014 matched$27 million for the three-yearyears ended December 31, 2017, 2016, and 2015. There were no significant compensation costs capitalized related to the performance period.share units during the years ended December 31, 2017, 2016, and 2015. As of December 31, 2017, total compensation cost of $29 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.
The fair value of each share unit awarded in 2015 under the
2014 Incentive Plan was determined to be $52.88, which wasis based on Ameren'sAmeren’s closing common share price at December 31st of $46.13 at December 31, 2014,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, 2015.1st 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 1.10%, 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 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. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2014. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.78%, 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 under the 2014 Incentive Plan along with the significant assumptions used to calculate the fair value of each share unit for the years ended December 31, 2017, 2016, and 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, 20152017, 20142016, and 20132015:
| | | | Ameren Missouri | | Ameren Illinois | | Ameren | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2015 | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | |
| 2017 | | | | | | |
| Federal statutory corporate income tax rate: | | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | | | | | |
| Depreciation differences | — |
| | (2 | ) | | (1 | ) | 1 |
| | (1 | ) | | — |
|
| Amortization of investment tax credit | (1 | ) | | — |
| | (1 | ) | |
| Amortization of deferred investment tax credit | | (1 | ) | | — |
| | (1 | ) |
| State tax | | 4 |
| | 6 |
| | 6 |
|
| TCJA | | 6 |
| | (1 | ) | | 14 |
|
| Tax credits | | (1 | ) | | — |
| | — |
|
| Other permanent items | | — |
| | (1 | ) | | (2 | ) |
| Effective income tax rate | | 44 | % | | 38 | % | | 52 | % |
| 2016 | | | | | | |
| Federal statutory corporate income tax rate: | | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | |
| Depreciation differences | | 1 |
| | — |
| | — |
|
| Amortization of deferred investment tax credit | | (1 | ) | | — |
| | — |
|
| State tax | | 3 |
| | 5 |
| | 4 |
|
Stock-based compensation(a) | | — |
| | — |
| | (2 | ) |
| Valuation allowance | | — |
| | — |
| | 1 |
|
| Other permanent items | | — |
| | (2 | ) | | (1 | ) |
| Effective income tax rate | | 38 | % | | 38 | % | | 37 | % |
| 2015 | | | | | | |
| Federal statutory corporate income tax rate: | | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | |
| Depreciation differences | | — |
| | (2 | ) | | (1 | ) |
| Amortization of deferred investment tax credit | | (1 | ) | | — |
| | (1 | ) |
| State tax | 3 |
| | 5 |
| | 5 |
| 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 investment tax credit | (1 | ) | | — |
| | (1 | ) | |
| State tax | 3 |
| | 6 |
| | 4 |
| |
| Other permanent items | — |
| | — |
| | 1 |
| |
| Effective income tax rate | 37 | % | | 41 | % | | 39 | % | |
| 2013 | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | |
| Increases (decreases) from: | | | | | | |
| Depreciation differences | — |
| | (1 | ) | | — |
| |
| Amortization of investment tax credit | (1 | ) | | — |
| | (1 | ) | |
| State tax | 3 |
| | 6 |
| | 4 |
| |
| Other permanent items | 1 |
| | — |
| | — |
| |
| Effective income tax rate | 38 | % | | 40 | % | | 38 | % | |
| |
| (a) | Reflects the adoption of authoritative accounting guidance related to share-based compensation, which resulted in the recognition of a $21 million income tax benefit in 2016. |
The following table presents the components of income tax expense (benefit) for the years ended December 31, 20152017, 20142016, and 20132015:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 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 |
|
| Deferred investment tax credits, amortization | (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 |
|
| Deferred investment tax credits, amortization | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 229 |
| | $ | 143 |
| | $ | 5 |
| | $ | 377 |
|
| 2013 | | | | | | | |
| Current taxes: | | | | | | | |
| Federal | $ | 136 |
| | $ | (15 | ) | | $ | (239 | ) | (a) | $ | (118 | ) |
| State | 41 |
| | 21 |
| | (43 | ) | (a) | 19 |
|
| Deferred taxes: | | | | | | | |
| Federal | 64 |
| | 99 |
| | 205 |
| (a) | 368 |
|
| State | 6 |
| | 6 |
| | 36 |
| (a) | 48 |
|
| Deferred investment tax credits, amortization | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense (benefit) | $ | 242 |
| | $ | 110 |
| | $ | (41 | ) | | $ | 311 |
|
| |
(a) | These amounts are substantially related to the reversal of unrecognized tax benefits as a result of IRS guidance related to the deductibility of expenditures to maintain, replace, or improve steam or electric power generation property, along with casualty loss deductions for storm damage. The amounts also reflect the increase in deferred tax expense due to available net operating losses. |
The Illinois corporate income tax rate was increased to 9.5% from January 2011 through December 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, 20152017 and 20142016:
| | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2015 | | | | | | | | |
| 2017 | | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | | | | | | | | |
| Plant related | $ | 2,931 |
| | $ | 1,587 |
| | $ | 37 |
| | $ | 4,555 |
| $ | 2,064 |
| | $ | 1,264 |
| | $ | 146 |
| | $ | 3,474 |
|
| Regulatory assets, net | 81 |
| | (1 | ) | | — |
| | 80 |
| |
| Regulatory assets and liabilities, net | | (317 | ) | | (206 | ) | | (24 | ) | | (547 | ) |
| Deferred employee benefit costs | (76 | ) | | (40 | ) | | (91 | ) | | (207 | ) | (53 | ) | | (17 | ) | | (61 | ) | | (131 | ) |
Revenue requirement reconciliation adjustments
| — |
| | 66 |
| | — |
| | 66 |
| — |
| | 20 |
| | — |
| | 20 |
|
| Tax carryforwards | (65 | ) | | (133 | ) | | (405 | ) | | (603 | ) | (31 | ) | | (43 | ) | | (287 | ) | | (361 | ) |
| Other | (27 | ) | | 1 |
| | 20 |
| | (6 | ) | (13 | ) | | 3 |
| | 61 |
| | 51 |
|
Total net accumulated deferred income tax liabilities (assets) (a) | $ | 2,844 |
| | $ | 1,480 |
| | $ | (439 | ) | | $ | 3,885 |
| $ | 1,650 |
| | $ | 1,021 |
| | $ | (165 | ) | | $ | 2,506 |
|
| 2014 | | | | | | | | |
| 2016 | | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | | | | | | | | |
| Plant related | $ | 2,776 |
| | $ | 1,393 |
| | $ | 16 |
| | $ | 4,185 |
| $ | 3,103 |
| | $ | 1,769 |
| | $ | 147 |
| | $ | 5,019 |
|
| Regulatory assets, net | 82 |
| | (5 | ) | | 1 |
| | 78 |
| |
| Regulatory assets and liabilities, net | | 75 |
| | (1 | ) | | — |
| | 74 |
|
| Deferred employee benefit costs | (80 | ) | | (45 | ) | | (95 | ) | | (220 | ) | (76 | ) | | (38 | ) | | (97 | ) | | (211 | ) |
Revenue requirement reconciliation adjustments
| — |
| | 66 |
| | 3 |
| | 69 |
| — |
| | 34 |
| | — |
| | 34 |
|
| Tax carryforwards | (107 | ) | | (139 | ) | | (429 | ) | | (675 | ) | (66 | ) | | (138 | ) | | (472 | ) | | (676 | ) |
| Other | 86 |
| | (22 | ) | | 70 |
| | 134 |
| (23 | ) | | 5 |
| | 42 |
| | 24 |
|
Total net accumulated deferred income tax liabilities (assets) (a) | $ | 2,757 |
| | $ | 1,248 |
| | $ | (434 | ) | | $ | 3,571 |
| $ | 3,013 |
| | $ | 1,631 |
| | $ | (380 | ) | | $ | 4,264 |
|
| |
(a) | Reflects the adoption of the new authoritative accounting guidance for the balance sheet classification of deferred income taxes. See Note 1 – Summary of Significant Accounting Policies for additional information. |
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, 20152017: and 2016:
| | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2017 | | | | | | | | |
| Net operating loss carryforwards: | | | | | | | | | | | | | | |
Federal(a) | $ | 35 |
| | $ | 127 |
| | $ | 245 |
| | $ | 407 |
| $ | — |
| | $ | 41 |
| | $ | 162 |
| | $ | 203 |
|
State(b) | 4 |
| | 4 |
| | 38 |
| | 46 |
| |
State(a) | | — |
| | — |
| | 32 |
| | 32 |
|
| Total net operating loss carryforwards | $ | 39 |
| | $ | 131 |
| | $ | 283 |
| | $ | 453 |
| $ | — |
| | $ | 41 |
| | $ | 194 |
| | $ | 235 |
|
| Tax credit carryforwards: | | | | | | | | | | | | | | |
Federal(c) | $ | 26 |
| | $ | 1 |
| | $ | 78 |
| | $ | 105 |
| |
State(d) | — |
| | 1 |
| | 40 |
| | 41 |
| |
State valuation allowance(e) | — |
| | — |
| | (2 | ) | | (2 | ) | |
Federal(b) | | $ | 31 |
| | $ | 2 |
| | $ | 80 |
| | $ | 113 |
|
State(c) | | — |
| | — |
| | 7 |
| | 7 |
|
| Total tax credit carryforwards | $ | 26 |
| | $ | 2 |
| | $ | 116 |
| | $ | 144 |
| $ | 31 |
| | $ | 2 |
| | $ | 87 |
| | $ | 120 |
|
Charitable contribution carryforwards(f)(d) | $ | — |
| | $ | — |
| | $ | 10 |
| | $ | 10 |
| $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 11 |
|
Valuation allowance(e) | — |
| | — |
| | (4 | ) | | (4 | ) | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
| $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
|
| 2016 | | | | | | | | |
| Net operating loss carryforwards: | | | | | | | | |
| Federal | | $ | 33 |
| | $ | 137 |
| | $ | 324 |
| | $ | 494 |
|
| State | | 4 |
| | — |
| | 41 |
| | 45 |
|
| Total net operating loss carryforwards | | $ | 37 |
| | $ | 137 |
| | $ | 365 |
| | $ | 539 |
|
| Tax credit carryforwards: | | | | | | | | |
| Federal | | $ | 29 |
| | $ | 1 |
| | $ | 79 |
| | $ | 109 |
|
| State | | — |
| | — |
| | 21 |
| | 21 |
|
| Total tax credit carryforwards | | $ | 29 |
| | $ | 1 |
| | $ | 100 |
| | $ | 130 |
|
| Charitable contribution carryforwards | | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | 18 |
|
| Valuation allowance | | — |
| | — |
| | (11 | ) | | (11 | ) |
| Total charitable contribution carryforwards | | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 7 |
|
| |
| (a) | Will begin to expire in 2029.between 2033 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 begin to expire in 2023.between 2029 and 2037. |
| |
| (c) | Will begin to expire in 2029.between2019 and 2022. |
| |
| (d) | Will begin to expire in 2016.between 2018 and 2021. |
| |
| (e) | See Schedule II under Part IV, Item 15, in this report for information on changes in the valuation allowance. |
| |
(f) | Will begin to expire in 2016. |
The following table presents the components of deferred tax assets relating to net operating loss carryforwards, tax credit carryforwards, and charitable contribution carryforwards at December 31, 2014:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| Net operating loss carryforwards: | | | | | | | |
Federal(a) | $ | 75 |
| | $ | 127 |
| | $ | 255 |
| | $ | 457 |
|
State(b) | 11 |
| | 10 |
| | 53 |
| | 74 |
|
| Total net operating loss carryforwards | $ | 86 |
| | $ | 137 |
| | $ | 308 |
| | $ | 531 |
|
| Tax credit carryforwards: | | | | | | | |
Federal(c) | $ | 21 |
| | $ | 1 |
| | $ | 77 |
| | $ | 99 |
|
State(d) | 1 |
| | 2 |
| | 33 |
| | 36 |
|
State valuation allowance(e) | (1 | ) | | (1 | ) | | (2 | ) | | (4 | ) |
| Total tax credit carryforwards | $ | 21 |
| | $ | 2 |
| | $ | 108 |
| | $ | 131 |
|
Charitable contribution carryforwards(f) | $ | — |
| | $ | — |
| | $ | 19 |
| | $ | 19 |
|
Valuation allowance(e) | — |
| | — |
| | (6 | ) | | (6 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 13 |
| | $ | 13 |
|
| |
(a) | Will begin to expire in 2028
|
| |
(b) | Will begin to expire in 2019. |
| |
(c) | Will begin to expire in 2029. |
| |
(d) | Began to expire in 2013. |
| |
(e) | See Schedule II under Part IV, Item 15, in this report for information on changes in the valuation allowance. |
| |
(f) | Began to expire in 2013. |
Uncertain Tax Positions
A reconciliationAs of the change in the unrecognized tax benefit balance during the years ended December 31, 2013, 2014,2017 and 2015, is as follows:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| Unrecognized tax benefits – January 1, 2013 | $ | 136 |
| | $ | 13 |
| | $ | 7 |
| | $ | 156 |
|
| Increases based on tax positions prior to 2013 | — |
| | 2 |
| | 5 |
| | 7 |
|
| Decreases based on tax positions prior to 2013 | (122 | ) | | (16 | ) | | (5 | ) | | (143 | ) |
| Increases based on tax positions related to 2013 | 16 |
| | — |
| | 53 |
| (a) | 69 |
|
| Changes related to settlements with taxing authorities | — |
| | — |
| | — |
| | — |
|
| Decreases related to the lapse of statute of limitations | 1 |
| | — |
| | — |
| | 1 |
|
| Unrecognized tax benefits – December 31, 2013 | $ | 31 |
| | $ | (1 | ) | | $ | 60 |
| | $ | 90 |
|
| Increases based on tax positions prior to 2014 | 1 |
| | 1 |
| | 4 |
| | 6 |
|
| Decreases based on tax positions prior to 2014 | (32 | ) | | (1 | ) | | (9 | ) | | (42 | ) |
| Increases based on tax positions related to 2014 | — |
| | — |
| | — |
| | — |
|
| Changes related to settlements with taxing authorities | — |
| | — |
| | — |
| | — |
|
| Increases related to the lapse of statute of limitations | — |
| | — |
| | — |
| | — |
|
| Unrecognized tax benefits – December 31, 2014 | $ | — |
| | $ | (1 | ) | | $ | 55 |
| | $ | 54 |
|
| Increases based on tax positions prior to 2015 | — |
| | 1 |
| | 1 |
| | 2 |
|
| Decreases based on tax positions prior to 2015 | — |
| | — |
| | (56 | ) | (a) | (56 | ) |
| Increases based on tax positions related to 2015 | — |
| | — |
| | — |
| | — |
|
| Changes related to settlements with taxing authorities | — |
| | — |
| | — |
| | — |
|
| Increases related to the lapse of statute of limitations | — |
| | — |
| | — |
| | — |
|
| Unrecognized tax benefits – December 31, 2015 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2013 | $ | 3 |
| | $ | — |
| | $ | 51 |
| (a) | $ | 54 |
|
| Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates as of December 31, 2014 | $ | — |
| | $ | (1 | ) | | $ | 53 |
| (a) | $ | 52 |
|
| Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2015 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| |
(a) | Primarily due to tax positions relating to the New AER divestiture. The income statement impact of this unrecognized tax benefit was included in "Income (loss) from discontinued operations, net of taxes" on Ameren's consolidated statement of income (loss). See Note 16 – Divestiture Transactions and Discontinued Operations for additional information. |
The Ameren Companies recognize interest charges (income) and penalties accrued on tax liabilities on a pretax basis as interest charges (income) or miscellaneous expense, respectively, in the statements of income.
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2013, 2014, and 2015, is as follows:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| Liability for interest – January 1, 2013 | $ | 8 |
| | $ | 1 |
| | $ | (3 | ) | | $ | 6 |
|
| Interest charges (income) for 2013 | (8 | ) | | (1 | ) | | 4 |
| | (5 | ) |
| Liability for interest – December 31, 2013 | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
|
| Interest charges (income) for 2014 | — |
| | — |
| | (1 | ) | | (1 | ) |
| Liability for interest – December 31, 2014 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Interest charges (income) for 2015 | — |
| | — |
| | — |
| | — |
|
| Liability for interest – December 31, 2015 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
As of December 31, 2013, 2014, and 2015,2016, the Ameren Companies have accrued no amount for penalties with respect to unrecognizeddid not record any uncertain tax benefits.positions.
In 2015, final settlements for tax years 2012 and 2013 were reached with the IRS. There were no uncertain tax positions related to the 2012 tax year, asThe 2015 settlement of December 31, 2014, so this settlement did not affect the amount of recorded unrecognized tax benefits during 2015. The settlement related to the 2013 tax year resolved the uncertain tax position associated with the final tax basis of New AER and the related tax benefit resulting from the divested merchant generation business. The settlement resulted in a reduction of Ameren's unrecognized tax benefits of $53 million and an increase to net income fromaffected discontinued operations. See Note 161 – Divestiture Transactions and Discontinued OperationsSummary 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.
In 2013, unrecognized tax benefits related to the deductibility of expenditures to maintain, replace, or improve steam or electric power generation property, along with casualty loss deductions for storm damage, were reduced by $103 million, $95 million, and $5 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. This reduction in unrecognized tax benefits did not affect income tax expense for the Ameren Companies. However, the liability for interest related to these unrecognized tax benefits was released in 2013. In 2013, Ameren adopted an accounting method change as a result of guidance issued by the IRS, with respect to the amount and timing of the deductions to maintain, replace, or improve generation property.
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, that are 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 2010, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for less than $1 million for the period from June 1, 2010, through May 31, 2013. 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 endingended 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
As a resultBased on the outcome of an IPAIPA-administered procurement event in 2011,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, approximately 40,800a set amount of megawatthours at approximately $29 per megawatthour duringa predetermined price over a specified period of time. The following table presents the 12 months ended May 31, 2013,agreements the companies have entered into, as well as the specified performance period, price, and approximately 40,800amount of megawatthours at approximately $28 per megawatthour duringincluded in each agreement:
|
| | | | | |
| IPA Procurement Event | Performance Period | MWh |
| | Average Price per MWh |
| May 2014 | January 2015 – February 2017 | 168,400 |
| $ | 51 |
| April 2015 | June 2015 – June 2017 | 667,000 |
| | 36 |
| September 2015 | November 2015 – May 2018 | 339,000 |
| | 38 |
| April 2016 | June 2017 – September 2018 | 375,200 |
| | 35 |
| September 2016 | May 2017 – September 2018 | 82,800 |
| | 34 |
| April 2017 | March 2019 – May 2020 | 85,600 |
| | 34 |
Collateral Postings
Under the 12 months ended May 31, 2014. Theterms of the Illinois energy product agreements forentered into through RFP processes administered by the period ended May 31, 2013, were for off-peak hours only.
As a resultIPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of an IPA procurement event in 2014,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, 2017 and 2016, there were no collateral postings required of Ameren Missouri related to the Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase approximately 168,400 megawatthours at approximately $51 per megawatthour during the period of January 1, 2015, through February 28, 2017.agreements.
As a result of an IPA procurement event in April 2015, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase 667,000 megawatthours at an average price of $36 per megawatthour during the period of June 1, 2015, through June 30, 2017. Also in September 2015, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase 339,000 megawatthours at an average price of $38 per megawatthour during the period of November 1, 2015, through May 31, 2018.
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 takesreceives transmission serviceservices from MISOATXI for theits retail load it serves in the AMIL pricing zone. ATXI is one of the
transmission owners in the AMIL pricing zone. Accordingly, ATXI receives transmission payments from Ameren Illinois through the MISO billing process.
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.
Collateral Postings
Under the terms of the Illinois power procurement 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, 2015 and 2014, there were no collateral postings required of Ameren Missouri related to the Illinois power procurement agreements.
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreement. AtAs of December 31, 20152017 and 2014,2016, Ameren Missouri accrued capital contributions fromhad income taxes payable to Ameren (parent) of $38$11 million and $9$16 million, respectively, pursuantincluded in “Accounts payable - affiliates” on its balance sheet. As of December 31, 2017 and 2016, Ameren Illinois had income taxes payable to Ameren (parent) of $17 million and $3 million, respectively, included in “Accounts payable - affiliates” on its balance sheet. See below for capital contributions received related to the tax allocation agreement.
Capital Contributions
In 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, 20152017, 20142016, and 20132015. 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 | | 2015 | $ | 15 |
| $ | (a) |
| Operating Revenues | | 2017 | $ | 23 |
| $ | (a) |
|
| with Ameren Illinois | | 2014 | | 5 |
| | (a) |
| | 2016 | | 28 |
| | (a) |
|
| | | | 2013 | | 3 |
| | (a) |
| | | 2015 | | 15 |
| | (a) |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2015 | | 25 |
| | 4 |
| Operating Revenues | | 2017 | | 26 |
| | 4 |
|
| rent and facility services | | 2014 | | 21 |
| | 2 |
| | 2016 | | 25 |
| | 5 |
|
| | | | 2013 | | 21 |
| | 1 |
| | | 2015 | | 25 |
| | 4 |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2015 | | 2 |
| | (b) |
| Operating Revenues | | 2017 | | (b) |
| | 1 |
|
| miscellaneous support services | | 2014 | | 1 |
| | (b) |
| | 2016 | | 1 |
| | (b) |
|
| | | 2013 | | 1 |
| | 3 |
| | 2015 | | 2 |
| | (b) |
|
| Total Operating Revenues | | 2015 | $ | 42 |
| $ | 4 |
| | 2017 | $ | 49 |
| $ | 5 |
|
| | | 2014 | | 27 |
| | 2 |
| | 2016 | | 54 |
| | 5 |
|
| | | | 2013 | | 25 |
| | 4 |
| | | 2015 | | 42 |
| | 4 |
|
| Ameren Illinois power supply | Purchased Power | | 2015 | $ | (a) |
| $ | 15 |
| Purchased Power | | 2017 | $ | (a) |
| $ | 23 |
|
| agreements with Ameren Missouri | | 2014 | | (a) |
| | 5 |
| | 2016 | | (a) |
| | 28 |
|
| | | | 2013 | | (a) |
| | 3 |
| | | 2015 | | (a) |
| | 15 |
|
| Ameren Illinois transmission | Purchased Power | | 2015 | | (a) |
| | 2 |
| Purchased Power | | 2017 | | (a) |
| | 2 |
|
| services with ATXI | | 2014 | | (a) |
| | 2 |
| |
| services from ATXI | | | 2016 | | (a) |
| | 2 |
|
| | | 2013 | | (a) |
| | 2 |
| | 2015 | | (a) |
| | 2 |
|
| Total Purchased Power | | 2015 | $ | (a) |
| $ | 17 |
| | 2017 | $ | (a) |
| $ | 25 |
|
| | | 2014 | | (a) |
| | 7 |
| | 2016 | | (a) |
| | 30 |
|
| | | 2013 | | (a) |
| | 5 |
| | 2015 | | (a) |
| | 17 |
|
| Ameren Services support services | Other Operations and | | 2015 | $ | 131 |
| $ | 119 |
| Other Operations and | | 2017 | $ | 149 |
| $ | 139 |
|
| agreement | Maintenance | | 2014 | | 124 |
| | 109 |
| Maintenance | | 2016 | | 129 |
| | 123 |
|
| | | | 2013 | | 116 |
| | 93 |
| | | 2015 | | 131 |
| | 119 |
|
| Total Other Operations and | | 2015 | $ | 131 |
| $ | 119 |
| |
| Maintenance Expenses | | 2014 | | 124 |
| | 109 |
| |
| | | | 2013 | | 116 |
| | 93 |
| |
| Money pool borrowings (advances) | Interest (Charges) | | 2015 | $ | (b) |
| $ | (b) |
| (Interest Charges) | | 2017 | $ | 1 |
| $ | (b) |
|
| | Income | | 2014 | | (b) |
| | (b) |
| Miscellaneous Income | | 2016 | | (b) |
| | (b) |
|
| | | | 2013 | | (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, 2015. The property coverage and the nuclear liability coverage must be renewed on 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 |
|
| $ | — |
| |
| Pool participation | 13,114 |
| (a) | 127 |
| (b) |
| | $ | 13,489 |
| (c) | $ | 127 |
| |
| Property damage: | | | | |
| Nuclear Electric Insurance Limited | $ | 2,750 |
| (d) | $ | 27 |
| (e) |
| European Mutual Association for Nuclear Insurance | 500 |
| (f) | — |
| |
| | $ | 3,250 |
| | $ | 27 |
| |
| Replacement power: | | | | |
| Nuclear Electric Insurance Limited | $ | 490 |
| (g) | $ | 10 |
| (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 $375 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. 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.
|
| |
(d) | NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance for both radiation and nonradiation events. An additional $500 million is provided for radiation events only for a total of $2.75 billion. |
| |
(e) | All NEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL. |
| |
(f) | European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.75 billion and $2.25 billion property coverage for radiation and nonradiation events, respectively, provided by NEIL. |
| |
(g) | 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 twelve 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 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 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, 20152017:
| | | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | After 5 Years | | Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | After 5 Years | | Total |
Ameren:(a) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Minimum capital lease payments(b) | $ | 33 |
| | $ | 33 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 329 |
| | $ | 491 |
| |
Minimum capital lease payments(b)(c) | | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 27 |
| | 27 |
| | 26 |
| | 25 |
| | 25 |
| | 73 |
| | 203 |
| 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 256 |
| | $ | 288 |
| $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
Operating leases(c) | 14 |
| | 13 |
| | 12 |
| | 12 |
| | 11 |
| | 30 |
| | 92 |
| |
| Operating leases | | 10 |
| | 9 |
| | 8 |
| | 6 |
| | 6 |
| | 14 |
| | 53 |
|
| Total lease obligations | $ | 20 |
| | $ | 19 |
| | $ | 18 |
| | $ | 19 |
| | $ | 18 |
| | $ | 286 |
| | $ | 380 |
| $ | 16 |
| | $ | 16 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 329 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Minimum capital lease payments(b) | $ | 33 |
| | $ | 33 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 329 |
| | $ | 491 |
| |
Minimum capital lease payments(b)(c) | | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 27 |
| | 27 |
| | 26 |
| | 25 |
| | 25 |
| | 73 |
| | 203 |
| 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 256 |
| | $ | 288 |
| $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
Operating leases(c) | 12 |
| | 11 |
| | 11 |
| | 11 |
| | 10 |
| | 29 |
| | 84 |
| |
| Operating leases | | 8 |
| | 8 |
| | 7 |
| | 6 |
| | 6 |
| | 14 |
| | 49 |
|
| Total lease obligations | $ | 18 |
| | $ | 17 |
| | $ | 17 |
| | $ | 18 |
| | $ | 17 |
| | $ | 285 |
| | $ | 372 |
| $ | 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 Plant,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 2016 through 2020 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, 20152017, 20142016, and 20132015:
| | | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Ameren(a) | $ | 36 |
| | $ | 37 |
| | $ | 32 |
| $ | 11 |
| | $ | 38 |
| | $ | 36 |
|
| Ameren Missouri | 34 |
| | 32 |
| | 29 |
| 10 |
| | 34 |
| | 34 |
|
| Ameren Illinois | 28 |
| | 25 |
| | 21 |
| 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, 20152017. 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, 20152017.
| | | | 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) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | $ | 664 |
| | $ | 249 |
| | $ | 51 |
| | $ | 241 |
| | $ | 3 |
| | $ | 115 |
| | $ | 1,323 |
| |
| 2017 | 685 |
| | 190 |
| | 46 |
| | 147 |
| | 4 |
| | 73 |
| | 1,145 |
| |
| 2018 | 204 |
| | 127 |
| | 68 |
| | 72 |
| | 5 |
| | 55 |
| | 531 |
| $ | 463 |
| | $ | 205 |
| | $ | 67 |
| | $ | 170 |
| | $ | 3 |
| | $ | 73 |
| | $ | 981 |
|
| 2019 | 110 |
| | 89 |
| | 24 |
| | 58 |
| | 5 |
| | 56 |
| | 342 |
| 383 |
| | 163 |
| | 26 |
| | 63 |
| | 4 |
| | 37 |
| | 676 |
|
| 2020 | — |
| | 43 |
| | 51 |
| | 58 |
| | 6 |
| | 57 |
| | 215 |
| 85 |
| | 110 |
| | 39 |
| | 14 |
| | 4 |
| | 36 |
| | 288 |
|
| 2021 | | 27 |
| | 46 |
| | 45 |
| | 3 |
| | 5 |
| | 25 |
| | 151 |
|
| 2022 | | — |
| | 11 |
| | 12 |
| | 2 |
| | 5 |
| | 25 |
| | 55 |
|
| Thereafter | — |
| | 60 |
| | 108 |
| | 539 |
| | 71 |
| | 350 |
| | 1,128 |
| — |
| | 38 |
| | 45 |
| | 18 |
| | 58 |
| | 95 |
| | 254 |
|
| Total | $ | 1,663 |
| | $ | 758 |
| | $ | 348 |
| | $ | 1,115 |
| | $ | 94 |
| | $ | 706 |
| | $ | 4,684 |
| $ | 958 |
| | $ | 573 |
| | $ | 234 |
| | $ | 270 |
| | $ | 79 |
| | $ | 291 |
| | $ | 2,405 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | $ | 664 |
| | $ | 46 |
| | $ | 51 |
| | $ | 23 |
| | $ | 3 |
| | $ | 46 |
| | $ | 833 |
| |
| 2017 | 685 |
| | 36 |
| | 46 |
| | 23 |
| | 4 |
| | 32 |
| | 826 |
| |
| 2018 | 204 |
| | 24 |
| | 68 |
| | 23 |
| | 5 |
| | 28 |
| | 352 |
| $ | 463 |
| | $ | 42 |
| | $ | 67 |
| | $ | — |
| | $ | 3 |
| | $ | 53 |
| | $ | 628 |
|
| 2019 | 110 |
| | 14 |
| | 24 |
| | 23 |
| | 5 |
| | 29 |
| | 205 |
| 383 |
| | 36 |
| | 26 |
| | — |
| | 4 |
| | 24 |
| | 473 |
|
| 2020 | — |
| | 10 |
| | 51 |
| | 23 |
| | 6 |
| | 30 |
| | 120 |
| 85 |
| | 29 |
| | 39 |
| | — |
| | 4 |
| | 24 |
| | 181 |
|
| 2021 | | 27 |
| | 13 |
| | 45 |
| | — |
| | 5 |
| | 25 |
| | 115 |
|
| 2022 | | — |
| | 6 |
| | 12 |
| | — |
| | 5 |
| | 25 |
| | 48 |
|
| Thereafter | — |
| | 23 |
| | 108 |
| | 84 |
| | 71 |
| | 183 |
| | 469 |
| — |
| | 16 |
| | 45 |
| | — |
| | 58 |
| | 75 |
| | 194 |
|
| Total | $ | 1,663 |
| | $ | 153 |
| | $ | 348 |
| | $ | 199 |
| | $ | 94 |
| | $ | 348 |
| | $ | 2,805 |
| $ | 958 |
| | $ | 142 |
| | $ | 234 |
| | $ | — |
| | $ | 79 |
| | $ | 226 |
| | $ | 1,639 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | $ | — |
| | $ | 203 |
| | $ | — |
| | $ | 218 |
| | $ | — |
| | $ | 31 |
| | $ | 452 |
| |
| 2017 | — |
| | 154 |
| | — |
| | 124 |
| | — |
| | 25 |
| | 303 |
| |
| 2018 | — |
| | 103 |
| | — |
| | 49 |
| | — |
| | 24 |
| | 176 |
| $ | — |
| | $ | 163 |
| | $ | — |
| | $ | 170 |
| | $ | — |
| | $ | 19 |
| | $ | 352 |
|
| 2019 | — |
| | 75 |
| | — |
| | 35 |
| | — |
| | 27 |
| | 137 |
| — |
| | 127 |
| | — |
| | 63 |
| | — |
| | 13 |
| | 203 |
|
| 2020 | — |
| | 33 |
| | — |
| | 35 |
| | — |
| | 27 |
| | 95 |
| — |
| | 81 |
| | — |
| | 14 |
| | — |
| | 12 |
| | 107 |
|
| 2021 | | — |
| | 33 |
| | — |
| | 3 |
| | — |
| | — |
| | 36 |
|
| 2022 | | — |
| | 5 |
| | — |
| | 2 |
| | — |
| | — |
| | 7 |
|
| Thereafter | — |
| | 37 |
| | — |
| | 455 |
| | — |
| | 167 |
| | 659 |
| — |
| | 22 |
| | — |
| | 18 |
| | — |
| | — |
| | 40 |
|
| Total | $ | — |
| | $ | 605 |
| | $ | — |
| | $ | 916 |
| | $ | — |
| | $ | 301 |
| | $ | 1,822 |
| $ | — |
| | $ | 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. From the beginning phases of sitingThe development and development to the operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities our activities involvecan 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 several environmental
regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for certain companies, including Ameren Missouri, that operatewhich operates coal-fired power plants. Significant new rulesAs of December 31, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the 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 require 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; new effluent standards applicable to wastewater discharges from power plants and new regulationsare regulated under the Clean Water Act thatAct. Such regulation could require significant capital expenditures, such as modifications to water intake structures or new cooling towersmore 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 new regulations are beingindividual 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, individually or the combined effects of newexisting environmental regulations could result in significant capital expenditures, and increased operating costs, for Ameren and Ameren Missouri. Compliance with all of 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 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 $600$325 million to $700$425 million in the aggregate from 20162018 through 20202022 in order to comply with existing environmental regulations. Ameren Missouri mayAdditional environmental controls beyond 2022 could be required to install additional air emissions controls within the next six to 10 years.required. This estimate includes ourof capital expenditures includes expenditures required forby the CCR regulations, that were published in 2015,by the Clean Water Act rule applicable to cooling water intake structures at existing power plants, under the Clean Water Act, and theby effluent limitation guidelines applicable to steam electric generating units, under the Clean Water Act, all of which are discussed below. These estimates do not include the impacts of the Clean Power Plan discussed below. Considerable uncertainty remains in these estimates. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimate due tobecause 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 new 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. There will be furtherThe second phase of emission reduction requirements, which were revised by the EPA in 2017 and potentially more2016, became 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, and operates two scrubbers at its Sioux energy center.center, and optimizes other existing pollution control equipment. Ameren Missouri doesdid not expect to make additional capital investments to comply with the current2017 CSAPR requirements. However, Ameren Missouri expects to incur additional costs as it lowersto 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 collectedrecovered from customers through the FAC or higher base rates.
In December 2011, the EPA issued the MATS under the Clean Air Act, which requires reductions in emissions of mercury and other hazardous air pollutants, such as acid gases, trace metals, and hydrogen chloride. The MATS do not require a specific control technology to achieve the emission reductions. The MATS apply to each unit at a coal-fired power plant. However, in certain cases, compliance can be achieved by averaging emissions from similar units at the same power plant. Compliance was required by April 2015 or, with a case-by-case extension, by April 2016. All of Ameren Missouri's coal-fired power plants will be in compliance before the required due dates. As part of Ameren Missouri's compliance plan, the Meramec energy center will burn natural gas at two of its units beginning in April 2016, thereby excluding such units from the MATS. In addition, Ameren Missouri is incurring additional costs to comply with the MATS. These higher costs are being collected from customers through the FAC or higher base rates.
CO2 Emissions Standards
TheIn 2015, the EPA issued the Clean Power Plan, which sets forthwould have established CO2emissions standards applicable to existing power plants, was issued by the EPA but stayed by theplants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In October 2017, the outcome of various appeals, as discussed below.
IfEPA announced a proposal to repeal the Clean Power Plan is ultimately upheldPlan. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input from stakeholders as issued, Ameren Missouri expects to incur increased fuel and operating costs, and make new or accelerated capital expenditures, in addition tohow the costs of making modifications to existing operations in order to achieve compliance. The Clean Power Plan required Missouri and Illinois to reduceEPA 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 2022 that require each state to demonstrate progress in achieving its CO2 reduction target. Ameren is evaluatingunder 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 investment. Significant uncertainty exists regarding the impact ofAir Act. Accordingly, we no longer expect the Clean Power Plan as its implementation will depend upon plans to be developed bytake effect. However, the states. Numerous legal challenges are pending, which could result in the rule being declared invalid or the nature and timing ofEPA may issue new requirements that would regulate CO2 emissions reductions being revised. In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until such time as legal appeals are concluded. The District of Columbia Circuit Court of Appeals has scheduled hearings for June 2016 on the legality of the rule. A decision by the District of Columbia Circuit Court of Appeals is expected to be issued later this year and additional appeals before the United States Supreme Court are likely. 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 implemented in substantially similar form to the rule when issued, 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 expects substantially all of these increased costs to be recoverable, subject to MoPSC prudence review, through higher rates to customers, which could be significant.
Also, in August 2015, the EPA issued final regulations that set 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.
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 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 EPA's complaint, as amended in October 2013, allegesalleged 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 then proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. 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 anticipates that a trialintends to appeal the liability ruling to the United States Court of this case could occur as early as 2016. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that it will be successful in its efforts.Appeals for the Eighth Circuit.
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. AAmong 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, andas well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of these mattersthis matter or the costs that might be incurred.
Clean Water Act
In August 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.All of Ameren
Missouri’s coal-fired and nuclear energy centers are subject to thisthe cooling water intake structures rule. EachThe rule will be implemented during the permit renewal process of Ameren Missouri’s affectedeach energy centers will become subject to the revised limitations when it renews itscenter’s water discharge permit. These permits are scheduled to be renewedpermit, 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 itsshould such implementation requires the installation of cooling towers orrequire extensive modifications to the cooling water systems and water discharge systems at ourAmeren Missouri’s energy centers, and if thosesuch investments are not recovered on a timely basis in electric rates charged to Ameren Missouri'sMissouri’s customers.
In September 2015, the EPA issued its final rule under the Clean Water Act 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 rule prohibits effluent discharges of certain, but not all, waste streams and imposes more stringent limitations on certain components in water discharges from power plants. All of Ameren Missouri’s coal-fired energy centers are subject to this rule and its implementation will be consistent with the water discharge permit process described above beginning as early as 2018. Ameren Missouri is evaluating the final rule, which became effective in January 2016, and the possible effects on its operations.
AshCCR Management
In 2015, the EPA issued regulations regarding the management and disposal of CCR that willfrom coal-fired energy centers. These regulations affect future CCR disposal and handling costs at Ameren Missouri'sMissouri’s energy centers. The regulations allow for the management of CCR as a solid waste, as well as for its continued beneficial uses, such as recycling, which could reduce the amount to be disposed. The regulations also establish criteria regarding the structural integrity, location, and operation of CCR impoundments and landfills. They require groundwater monitoring and closure of impoundments if theperformance criteria relating to groundwater standardsimpacts 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 Missouri 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.
The new regulations do not apply to ash ponds at plants no longer in operation, such as Ameren’s Meredosia and Hutsonville energy centers.
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, as required by federalsubstances. Federal and state law. Such laws can require that 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, 2015,2017, 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 2025.2023. 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 adjustment ratecost riders. Costs are subject to annual prudence review by the ICC. As of December 31, 2015,2017, Ameren Illinois estimated the obligation related to these former MGP sites at $232$175 million to $313$249 million. Ameren and Ameren Illinois recorded a liability of $232$175 million to represent theirthe estimated minimum obligation for these sites, as no other amount within the range was a better estimate.
The scope and extent to whichof the remediation activities at these former MGP sites are remediated may increase as remediation efforts continue. Considerable uncertainty remains in these estimates asbecause many site-specific factors can influence the ultimate actual costs, including site-specific 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 Illinois formerly used an off-site landfill, which Ameren Illinois did not own, in connection with the operation of a previously owned energy center. Ameren Illinois could be required to perform certain maintenance activities at that landfill, which is now closed. As of December 31, 2015, Ameren Illinois estimated the obligation related to this site at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of some underground storage tanks and a water treatment plant in Illinois. As of December 31, 2015, Ameren Illinois recorded a liability of $0.7 million to represent its best estimate of the obligation for these sites.
In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to a former coal tar distillery in St. Louis, Missouri, operated by Koppers Company or its predecessor and successor companies. While Ameren Missouri is the current owner of the site, it did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other potentially responsible parties, have completed site investigation activities and have submitted their findings to the EPA. As of December 31, 2015, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
Ameren Missouri also participated in the investigation of severalvarious sites known as Sauget Area 2 located in Sauget, Illinois. In 2000, the EPA notified
Ameren Missouri and numerous other companies including Solutia, Inc., that former landfills and lagoons at those sites may contain soil and groundwater contamination. These sites are known as Sauget Area 2. 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 as a landfill.
In December 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation alternativesactions 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, 2015,2017 and 2016, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.
In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri-owned substation in St. Charles, Missouri. As of December 31, 2015, Ameren Missouri estimated and recorded a $0.6 million liability related to the site. Although monitoring will continue for some time, no significant additional remediation measures are anticipated.
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.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. The breach resulted in significant flooding in the local area, which damaged a state park. Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles.
As of December 31, 2015, Ameren Missouri had an insurance receivable of $41 million. In February 2016, Ameren Missouri and an insurer that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident reached a settlement that resulted in Ameren Missouri receiving $42 million. As a result of this settlement, the receivable was included in “Miscellaneous accounts and notes receivable” on Ameren’s and Ameren Missouri’s balance sheets as of December 31, 2015 whereas previously this receivable was included in “Other assets” on their respective balance sheets as of December 31, 2014.
Asbestos-related Litigation
Ameren, Ameren Missouri, and Ameren Illinois have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from
asbestos exposure at our present or former energy centers. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with 75 as the average number of parties as of December 31, 2015. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.
The following table presents the pending asbestos-related lawsuits filed against Ameren Missouri and Ameren Illinois as of December 31, 2015:
|
| | | | |
Ameren Missouri | | Ameren Illinois | | Total(a) |
| 26 | | 38 | | 48 |
| |
(a) | Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants. |
At December 31, 2015, Ameren, Ameren Missouri, and Ameren Illinois had liabilities of $8 million, $3 million, and $5 million, respectively, recorded to represent their best estimates of their obligations related to asbestos claims.
Ameren Illinois has a tariff rider to recover the costs of IP asbestos-related litigation claims, 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 a trust fund that was established when Ameren acquired IP. At December 31, 2015, the trust fund balance was $22 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. The rider will permit recovery from electric customers within IP’s historical service territory.
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.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, 2015, representing their estimate2017, to represent the payments made in February 2018 under the settlement agreement.
NOTE 15 – SEGMENT INFORMATION
Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of taxes and fees due as a resultthe operations of this lawsuit. The ultimate resolution of any unpaid municipal tax or fees could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri believes its defenses are meritoriousIllinois 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 is defending itself vigorously; however, there can be no assurances that ATXI. The category called Other primarily includes Ameren parent company activities and Ameren Services.
Ameren Missouri will be successful in its efforts.
NOTE 16 – DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
On December 2, 2013,has one segment. Ameren completed the divestiture of New AER to IPH in accordance with the transaction agreement betweenIllinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and IPH dated March 14, 2013, as amended by a letter agreement dated December 2, 2013. Pursuant to that agreement, in 2015, Ameren paid $25 million related to a previously-recorded liability and concluded its obligations to provide credit support to New AER with no resulting additional impact to its results of operations. The transaction agreement with IPH, as amended, provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold by Medina Valley and if Medina Valley receives additional proceeds from such sale, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the $137.5 million previously paid to Genco.
On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower 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. Medina Valley received the escrow balance from Rockland Capital and expects to pay Genco its portion of that escrow balance during the first quarter of 2016.
Discontinued Operations Presentation
All matters related to the final tax basis of New AER and the related tax benefit resulting from the divested merchant generation business have been resolved with the completion of the IRS audit for 2013. During 2015, based on the completion of the IRS audit, Ameren removed a reserve for unrecognized tax benefits recorded in 2013 and recognized a tax benefit from discontinued operations.Illinois Transmission. See Note 131 – Income TaxesSummary of Significant Accounting Policies for additional information regarding the operations of Ameren Companies’ uncertainMissouri, Ameren Illinois, and ATXI.
Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax positions.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 and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.
The following table presents the components of discontinued operations in Ameren's consolidated statement oftables present revenues, net income (loss)attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the years ended December 31, 2015, 2014,2017, 2016, and 2013:2015. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.
|
| | | | | | | | | | | | |
| | Year ended | |
| | 2015 | | 2014 | | 2013 | |
| Operating revenues | $ | — |
| | $ | 1 |
| | $ | 1,037 |
| |
| Operating benefits (expenses) | 1 |
|
| (2 | ) | | (1,207 | ) | (a) |
| Operating income (loss) | 1 |
| | (1 | ) | | (170 | ) | |
| Other income (loss) | — |
| | — |
| | (1 | ) | |
| Interest charges | — |
| | — |
| | (39 | ) | |
| Income (loss) before income taxes | 1 |
| | (1 | ) | | (210 | ) | |
| Income tax (expense) benefit | 50 |
| | — |
| | (13 | ) | |
| Income (loss) from discontinued operations, net of taxes | $ | 51 |
| | $ | (1 | ) | | $ | (223 | ) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Consolidated |
| 2017 | | | | | | | | | | | | | |
| External revenues | $ | 3,490 |
| | $ | 1,565 |
| | $ | 742 |
| | $ | 382 |
| | $ | (2 | ) | | $ | — |
| | $ | 6,177 |
|
| Intersegment revenues | 49 |
| | 4 |
| | 1 |
| | 44 |
| (a) | — |
| | (98 | ) | | — |
|
| Depreciation and amortization | 533 |
| | 239 |
| | 59 |
| | 60 |
| | 5 |
| | — |
| | 896 |
|
| Interest income | 27 |
| | 7 |
| | — |
| | — |
| | 11 |
| | (11 | ) | | 34 |
|
| Interest charges | 207 |
| | 73 |
| | 36 |
| | 67 |
| (b) | 19 |
| | (11 | ) | | 391 |
|
| Income taxes | 254 |
| | 83 |
| | 36 |
| | 90 |
| | 113 |
| | — |
| | 576 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 323 |
| | 131 |
| | 60 |
| | 140 |
| | (131 | ) | | — |
| | 523 |
|
| Capital expenditures | 773 |
| | 476 |
| | 245 |
| | 644 |
| | 1 |
| | (7 | ) | | 2,132 |
|
| 2016 | | | | | | | | | | | | | |
| External revenues | $ | 3,469 |
| | $ | 1,545 |
| | $ | 753 |
| | $ | 309 |
| | $ | — |
| | $ | — |
| | $ | 6,076 |
|
| Intersegment revenues | 54 |
| | 4 |
| | 1 |
| | 46 |
| (a) | — |
| | (105 | ) | | — |
|
| Depreciation and amortization | 514 |
| | 226 |
| | 55 |
| | 43 |
| | 7 |
| | — |
| | 845 |
|
| Interest income | 28 |
| | 11 |
| | — |
| | 1 |
| | 11 |
| | (11 | ) | | 40 |
|
| Interest charges | 211 |
| | 72 |
| | 34 |
| | 58 |
| (b) | 18 |
| | (11 | ) | | 382 |
|
| Income taxes | 216 |
| | 78 |
| | 39 |
| | 74 |
| | (25 | ) | | — |
| | 382 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 357 |
| | 126 |
| | 59 |
| | 117 |
| | (6 | ) | | — |
| | 653 |
|
| Capital expenditures | 738 |
| | 470 |
| | 181 |
| | 689 |
| | 4 |
| | (6 | ) | | 2,076 |
|
| 2015 | | | | | | | | | | | | | |
| External revenues | $ | 3,566 |
| | $ | 1,529 |
| | $ | 782 |
| | $ | 219 |
| | $ | 2 |
| | $ | — |
| | $ | 6,098 |
|
| Intersegment revenues | 43 |
| | 3 |
| | 1 |
| | 40 |
| (a) | — |
| | (87 | ) | | — |
|
| Depreciation and amortization | 492 |
| | 212 |
| | 52 |
| | 33 |
| | 7 |
| | — |
| | 796 |
|
| Interest income | 28 |
| | 12 |
| | — |
| | — |
| | 7 |
| | (6 | ) | | 41 |
|
| Interest charges | 219 |
| | 71 |
| | 35 |
| | 35 |
| (b) | 1 |
| | (6 | ) | | 355 |
|
| Income taxes | 209 |
| | 71 |
| | 24 |
| | 51 |
| | 8 |
| | — |
| | 363 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 352 |
| | 123 |
| | 37 |
| | 83 |
| | (16 | ) | | — |
| | 579 |
|
| Capital expenditures | 622 |
| | 491 |
| | 133 |
| | 669 |
| | 2 |
| | — |
| | 1,917 |
|
| |
| (a) | Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
| |
| (b) | Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent). |
Ameren Illinois
|
| | | | | | | | | | | | | | | | | | | | |
| | 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 |
| |
| Intersegment revenues | — |
| | — |
| | 45 |
| (a) | (45 | ) | | — |
| |
| Depreciation and amortization | 226 |
| | 55 |
| | 38 |
| | — |
| | 319 |
| |
| Interest income | 11 |
| | — |
| | 1 |
| | — |
| | 12 |
| |
| Interest charges | 72 |
| | 34 |
| | 34 |
| | — |
| | 140 |
| |
| Income taxes | 78 |
| | 39 |
| | 41 |
| | — |
| | 158 |
| |
| Net income available to common shareholder | 126 |
| | 59 |
| | 67 |
| | — |
| | 252 |
| |
| Capital expenditures | 470 |
| | 181 |
| | 273 |
| | — |
| | 924 |
| |
| 2015 | | | | | | | | | | |
| External revenues | $ | 1,532 |
| | $ | 783 |
| | $ | 151 |
| | $ | — |
| | $ | 2,466 |
| |
| Intersegment revenues | — |
| | — |
| | 38 |
| (a) | (38 | ) | | — |
| |
| Depreciation and amortization | 212 |
| | 52 |
| | 31 |
| | — |
| | 295 |
| |
| Interest income | 12 |
| | — |
| | — |
| | — |
| | 12 |
| |
| Interest charges | 71 |
| | 35 |
| | 25 |
| | — |
| | 131 |
| |
| Income taxes | 71 |
| | 24 |
| | 32 |
| | — |
| | 127 |
| |
| Net income available to common shareholder | 123 |
| | 37 |
| | 54 |
| | — |
| | 214 |
| |
| Capital expenditures | 491 |
| | 133 |
| | 294 |
| | — |
| | 918 |
| |
| |
| (a) | Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2017 | | | 2016 |
| Quarter ended | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 |
| Operating revenues | $ | 1,514 |
| | $ | 1,538 |
| | $ | 1,723 |
| | $ | 1,402 |
| | | $ | 1,434 |
| | $ | 1,427 |
| | $ | 1,859 |
| | $ | 1,356 |
|
| Operating income | 254 |
| | 398 |
| | 581 |
| | 225 |
| | | 220 |
| | 325 |
| | 691 |
| | 145 |
|
| Net income (loss) | 104 |
| | 194 |
| | 290 |
| | (59 | ) | (a) | | 107 |
| | 148 |
| | 371 |
| | 33 |
|
| Net income (loss) attributable to Ameren common shareholders | $ | 102 |
| | $ | 193 |
| | $ | 288 |
| | $ | (60 | ) | | | $ | 105 |
| | $ | 147 |
| | $ | 369 |
| | $ | 32 |
|
| Earnings (loss) per common share – basic | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.19 |
| | $ | (0.24 | ) | | | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
|
Earnings (loss) per common share – diluted(b) | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.18 |
| | $ | (0.24 | ) | | | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
|
| |
(a) | Includes an increase to income tax expense of $154 million recorded in 2017 as a result of the TCJA. |
| |
| (b) | The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is because of the effects of rounding and the changes in the number of weighted-average diluted shares outstanding each period. |
|
| | | | | | | | | | | | | | | | |
Ameren Missouri Quarter ended | | Operating Revenues | | Operating Income | | Net Income (Loss) | | Net Income (Loss) Available to Common Shareholder |
| March 31, 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 $201 million pretax loss on disposal relating toresult of the New AER divestiture.TCJA. |
The following table presents the carrying amounts of the components of assets and liabilities of Ameren's discontinued operations, which consist primarily of AROs and related deferred income tax assets associated with the abandoned Meredosia and Hutsonville energy centers, at December 31, 2015 and 2014: |
| | | | | | | |
| | December 31, 2015 | | December 31, 2014 |
| Assets of discontinued operations | | | |
| Accumulated deferred income taxes, net | $ | 14 |
| | $ | 15 |
|
| Total assets of discontinued operations | $ | 14 |
| | $ | 15 |
|
| Liabilities of discontinued operations | | | |
| Accounts payable and other current obligations | $ | 1 |
| | $ | 1 |
|
Asset retirement obligations(a) | 28 |
| | 32 |
|
| Total liabilities of discontinued operations | $ | 29 |
| | $ | 33 |
|
|
| | | | | | | | | | | | | | | | |
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 is demolishingIllinois changed the Hutsonville energy centermethod it used to recognize its interim-period revenue. Ameren Illinois now recognizes revenue consistent with the timing of incurred electric distribution recoverable costs, and expectsit 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 demolishearnings in 2017 in comparison to 2016 for the Meredosia energy center beginningfirst, second, and fourth quarters and a decrease to earnings in 2016.the third quarter. The change in interim period revenue recognition did not affect 2017 annual earnings. |
NOTE 17 – SEGMENT INFORMATION
Ameren has two reportable segments: Ameren Missouri and Ameren Illinois. Ameren Missouri and Ameren Illinois each have one reportable segment. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all the operations of Ameren Missouri as described in Note 1 – Summary of Significant Accounting Policies. The Ameren Illinois segment for
both Ameren and Ameren Illinois consists of all of the operations of Ameren Illinois as described in Note 1 – Summary of Significant Accounting Policies. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. The Other category also includes certain corporate activities previously included in the Merchant Generation segment. See Note 16 – Divestiture Transactions and Discontinued Operations for additional information.
The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren common shareholders and capital expenditures from continuing operations for the years ended December 31, 2015, 2014, and 2013, and total assets in continuing operations as of December 31, 2015, 2014, and 2013:
|
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Intersegment Eliminations | | Consolidated | |
| 2015 | | | | | | | | | | |
| External revenues | $ | 3,566 |
| | $ | 2,462 |
| | $ | 70 |
| | $ | — |
| | $ | 6,098 |
| |
| Intersegment revenues | 43 |
| | 4 |
| | 2 |
| | (49 | ) | | — |
| |
| Depreciation and amortization | 492 |
| | 295 |
| | 9 |
| | — |
| | 796 |
| |
| Interest and dividend income | 28 |
| | 12 |
| | 1 |
| | — |
| | 41 |
| |
| Interest charges | 219 |
| | 131 |
| | 5 |
| | — |
| | 355 |
| |
| Income taxes | 209 |
| | 127 |
| | 27 |
| | — |
| | 363 |
| |
| Net income attributable to Ameren common shareholders from continuing operations | 352 |
| | 214 |
| | 13 |
| | — |
| | 579 |
| |
| Capital expenditures | 622 |
| | 918 |
| | 377 |
| (a) | — |
| | 1,917 |
| |
Total assets(c) | 13,851 |
| | 8,903 |
| | 1,139 |
| | (267 | ) | | 23,626 |
| (b) |
| 2014 | | | | | | | | | | |
| External revenues | $ | 3,526 |
| | $ | 2,496 |
| | $ | 31 |
| | $ | — |
| | $ | 6,053 |
| |
| Intersegment revenues | 27 |
| | 2 |
| | 2 |
| | (31 | ) | | — |
| |
| Depreciation and amortization | 473 |
| | 263 |
| | 9 |
| | — |
| | 745 |
| |
| Interest and dividend income | 28 |
| | 7 |
| | 2 |
| | — |
| | 37 |
| |
| Interest charges | 211 |
| | 112 |
| | 18 |
| | — |
| | 341 |
| |
| Income taxes | 229 |
| | 143 |
| | 5 |
| | — |
| | 377 |
| |
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 390 |
| | 201 |
| | (4 | ) | | — |
| | 587 |
| |
| Capital expenditures | 747 |
| | 835 |
| | 203 |
| (a) | — |
| | 1,785 |
| |
Total assets(c) | 13,474 |
| | 8,204 |
| | 799 |
| | (203 | ) | | 22,274 |
| (b) |
| 2013 | | | | | | | | | | |
| External revenues | $ | 3,516 |
| | $ | 2,307 |
| | $ | 15 |
| | $ | — |
| | $ | 5,838 |
| |
| Intersegment revenues | 25 |
| | 4 |
| | 2 |
| | (31 | ) | | — |
| |
| Depreciation and amortization | 454 |
| | 243 |
| | 9 |
| | — |
| | 706 |
| |
| Interest and dividend income | 27 |
| | 2 |
| | 1 |
| | — |
| | 30 |
| |
| Interest charges | 210 |
| | 143 |
| | 45 |
| | — |
| | 398 |
| |
| Income taxes (benefit) | 242 |
| | 110 |
| | (41 | ) | | — |
| | 311 |
| |
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 395 |
| | 160 |
| | (43 | ) | | — |
| | 512 |
| |
| Capital expenditures | 648 |
| | 701 |
| | 30 |
| (a) | — |
| | 1,379 |
| |
Total assets(c) | 12,867 |
| | 7,397 |
| | 711 |
| | (233 | ) | | 20,742 |
| (b) |
| |
(a)ITEM 9. | Includes the elimination of intercompany transfers. |
| |
(b) | Excludes total assets from discontinued operations of $14 million, $15 million, and $165 million as of December 31, 2015, 2014, and 2013, respectively.
|
| |
(c) | Reflects the adoption of the new authoritative accounting guidance for the presentation of debt issuance costs and balance sheet classification of deferred income taxes. See Note 1 – Summary of Significant Accounting Policies for additional information.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2015 | | | 2014 |
Quarter ended(a) | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 |
| Operating revenues | $ | 1,556 |
| | $ | 1,401 |
| | $ | 1,833 |
| | $ | 1,308 |
| | | $ | 1,594 |
| | $ | 1,419 |
| | $ | 1,670 |
| | $ | 1,370 |
|
| Operating income | 256 |
| | 237 |
| | 626 |
| | 140 |
| | | 246 |
| | 322 |
| | 561 |
| | 125 |
|
| Net income | 110 |
| | 151 |
| | 345 |
| | 30 |
| | | 98 |
| | 150 |
| | 295 |
| | 49 |
|
| Net income attributable to Ameren common shareholders – continuing operations | $ | 108 |
| | $ | 98 |
| | $ | 343 |
| | $ | 30 |
| | | $ | 97 |
| | $ | 150 |
| | $ | 294 |
| | $ | 46 |
|
| Net income (loss) attributable to Ameren common shareholders – discontinued operations | — |
| | 52 |
| | — |
| | (1 | ) | | | (1 | ) | | (1 | ) | | (1 | ) | | 2 |
|
| Net income attributable to Ameren common shareholders | $ | 108 |
| | $ | 150 |
| | $ | 343 |
| | $ | 29 |
| | | $ | 96 |
| | $ | 149 |
| | $ | 293 |
| | $ | 48 |
|
| Earnings per common share – basic – continuing operations | $ | 0.45 |
| | $ | 0.40 |
| | $ | 1.42 |
| | $ | 0.12 |
| | | $ | 0.40 |
| | $ | 0.62 |
| | $ | 1.21 |
| | $ | 0.19 |
|
| Earnings (loss) per common share – basic – discontinued operations | — |
| | 0.21 |
| | — |
| | — |
| | | — |
| | (0.01 | ) | | — |
| | 0.01 |
|
| Earnings per common share – basic | $ | 0.45 |
| | $ | 0.61 |
| | $ | 1.42 |
| | $ | 0.12 |
| | | $ | 0.40 |
| | $ | 0.61 |
| | $ | 1.21 |
| | $ | 0.20 |
|
| Earnings per common share – diluted – continuing operations | $ | 0.45 |
| | $ | 0.40 |
| | $ | 1.41 |
| | $ | 0.12 |
| | | $ | 0.40 |
| | $ | 0.62 |
| | $ | 1.20 |
| | $ | 0.19 |
|
| Earnings (loss) per common share – diluted – discontinued operations | — |
| | 0.21 |
| | — |
| | — |
| | | — |
| | (0.01 | ) | | — |
| | 0.01 |
|
| Earnings per common share – diluted | $ | 0.45 |
| | $ | 0.61 |
| | $ | 1.41 |
| | $ | 0.12 |
| | | $ | 0.40 |
| | $ | 0.61 |
| | $ | 1.20 |
| | $ | 0.20 |
|
| |
(a)
| The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is because of the effects of rounding and the changes in the number of weighted-average diluted shares outstanding each period. |
|
| | | | | | | | | | | | | | | | |
| Ameren Missouri Quarter ended | | Operating Revenues | | Operating Income | | Net Income (Loss) | | Net Income (Loss) Available to Common Shareholder |
| March 31, 2015 | | $ | 800 |
| | $ | 115 |
| | $ | 42 |
| | $ | 41 |
|
| March 31, 2014 | | 817 |
| | 119 |
| | 48 |
| | 47 |
|
| June 30, 2015 | | 884 |
| | 146 |
| | 62 |
| | 61 |
|
| June 30, 2014 | | 900 |
| | 243 |
| | 127 |
| | 126 |
|
| September 30, 2015 | | 1,171 |
| | 423 |
| | 240 |
| | 239 |
|
| September 30, 2014 | | 1,097 |
| | 394 |
| | 223 |
| | 222 |
|
| December 31, 2015 | | 754 |
| | 58 |
| | 11 |
| | 11 |
|
| December 31, 2014 | | 739 |
| | 29 |
| | (5 | ) | | (5 | ) |
|
| | | | | | | | | | | | | | | | |
| Ameren Illinois Quarter ended | | Operating Revenues | | Operating Income | | Net Income | | Net Income Available to Common Shareholder |
| March 31, 2015 | | $ | 745 |
| | $ | 120 |
| | $ | 54 |
| | $ | 53 |
|
| March 31, 2014 | | 774 |
| | 120 |
| | 54 |
| | 53 |
|
| June 30, 2015 | | 513 |
| | 83 |
| | 32 |
| | 31 |
|
| June 30, 2014 | | 519 |
| | 75 |
| | 29 |
| | 28 |
|
| September 30, 2015 | | 655 |
| | 189 |
| | 98 |
| | 98 |
|
| September 30, 2014 | | 572 |
| | 158 |
| | 75 |
| | 75 |
|
| December 31, 2015 | | 553 |
| | 74 |
| | 33 |
| | 32 |
|
| December 31, 2014 | | 633 |
| | 97 |
| | 46 |
| | 45 |
|
| |
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, 2015,2017, 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, 2015,2017, 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, 2015.2017. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2015,2017, 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 20152017 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 20162018 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 20162018 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 each of Walter J. Galvin and J. Edward Coleman qualifieseach 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 20162018 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 20162018 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, 2015,2017, 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(b) | | 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(a)(b) | | 3,186,287 |
| | (c) |
| | 6,423,549 |
| | 1,834,043 |
| | (c) |
| | 4,893,953 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 3,186,287 |
| | (c) |
| | 6,423,549 |
| | 1,834,043 |
| | (c) |
| | 4,893,953 |
|
| |
| (a) | Consists of the 2006 Incentive Plan and the 2014 Incentive Plan. The 2014 Plan replaced the 2006 Plan for any new grants made after April 24, 2014. |
| |
(b) | Pursuant to grants of performance share units (PSUs) under the 20062014 Incentive Plan, 1,763,644 of the securities represent the estimated number of PSUs that were vested as of December 31, 2015 (including accrued and reinvested dividends), and 1,371,7321,767,462 of the securities represent the target number of PSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 20152017 (including outstanding awards under the 2014 Incentive Plan as of December 31, 2015)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 20162018 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. 50,911Also, 66,581 of the securities represent shares that may be issued as of December 31, 2015,2017, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for members of the board of directors. |
| |
| (b) | Consists of the 2014 Incentive Plan. |
| |
| (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 20162018 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 20162018 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 20162018 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 20162018 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 20162018 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 (Loss) – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Consolidated Statement of Comprehensive Income (Loss) – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Consolidated Balance Sheet – December 31, 20152017 and 20142016 | |
Consolidated Statement of Cash Flows – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
| Ameren Missouri | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Balance Sheet – December 31, 20152017 and 20142016 | |
Statement of Cash Flows – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
| Ameren Illinois | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Balance Sheet – December 31, 20152017 and 20142016 | |
Statement of Cash Flows – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
| | |
| (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, 2015, 2014,2017, 2016, and 20132015 | |
Condensed Balance Sheet – December 31, 20152017 and 20142016 | |
Condensed Statement of Cash Flows – Years Ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
Schedule II – | |
| Ameren | |
Valuation and Qualifying Accounts for the years ended December 31, 2015, 2014,2017, 2016, and 20132015 | |
| 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, 2015, 2014, and 2013 | |
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) | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
| Operating expenses | 14 |
| | 11 |
| | 26 |
| 13 |
| | 14 |
| | 14 |
|
| Operating loss | (14 | ) | | (11 | ) | | (26 | ) | (13 | ) | | (14 | ) | | (14 | ) |
| Equity in earnings of subsidiaries | 600 |
| | 607 |
| | 546 |
| 659 |
| | 663 |
| | 600 |
|
| Interest income from affiliates | 6 |
| | 3 |
| | 3 |
| 9 |
| | 10 |
| | 6 |
|
| Total other income (expense), net | (5 | ) | | 2 |
| | (5 | ) | |
| Total other expense, net | | — |
| | (5 | ) | | (5 | ) |
| Interest charges | 3 |
| | 16 |
| | 42 |
| 31 |
| | 28 |
| | 3 |
|
| Income tax (benefit) | 5 |
| | (2 | ) | | (36 | ) | 101 |
| | (27 | ) | | 5 |
|
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | 579 |
| | 587 |
| | 512 |
| 523 |
| | 653 |
| | 579 |
|
Net Income (Loss) Attributable to Ameren Common Shareholders – Discontinued Operations | 51 |
| | (1 | ) | | (223 | ) | |
| Net Income Attributable to Ameren Common Shareholders – Discontinued Operations | | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 630 |
| | $ | 586 |
| | $ | 289 |
| $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | | | | | | |
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | $ | 579 |
| | $ | 587 |
| | $ | 512 |
| $ | 523 |
| | $ | 653 |
| | $ | 579 |
|
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $16, respectively | 6 |
| | (12 | ) | | 30 |
| |
| 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 | 585 |
| | 575 |
| | 542 |
| 528 |
| | 633 |
| | 585 |
|
| Net Income (Loss) Attributable to Ameren Common Shareholders – Discontinued Operations | 51 |
| | (1 | ) | | (223 | ) | |
| Other Comprehensive Loss from Discontinued Operations, Net of Income taxes | — |
| | — |
| | (19 | ) | |
| Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Common Shareholders | 51 |
| | (1 | ) | | (242 | ) | |
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 636 |
| | $ | 574 |
| | $ | 300 |
| $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
| | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET | | (In millions) | December 31, 2015 | | December 31, 2014 | December 31, 2017 | | December 31, 2016 |
| Assets: | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 1 |
| $ | — |
| | $ | 1 |
|
| Advances to money pool | — |
| | 55 |
| 13 |
| | 27 |
|
| Accounts receivable – affiliates | 53 |
| | 28 |
| 46 |
| | 31 |
|
| Notes receivable – affiliates | — |
| | 94 |
| |
| Miscellaneous accounts and notes receivable | 3 |
| | 39 |
| — |
| | 26 |
|
| Other current assets | 9 |
| | 14 |
| 8 |
| | 8 |
|
| Total current assets | 65 |
| | 231 |
| 67 |
| | 93 |
|
| Investments in subsidiaries – continuing operations | 7,231 |
| | 6,680 |
| |
| Investment in subsidiary – discontinued operations | (4 | ) | | (4 | ) | |
| Investments in subsidiaries | | 7,944 |
| | 7,498 |
|
| Note receivable – ATXI | 290 |
| | 100 |
| 75 |
| | 350 |
|
| Accumulated deferred income taxes, net | 426 |
| | 407 |
| 222 |
| | 419 |
|
| Other assets | 158 |
| | 152 |
| 140 |
| | 135 |
|
| Total assets | $ | 8,166 |
| | $ | 7,566 |
| $ | 8,448 |
| | $ | 8,495 |
|
| Liabilities and Shareholders’ Equity: | | | | | | |
| Short-term debt | 301 |
| | 585 |
| 383 |
| | 507 |
|
| Borrowings from money pool | 14 |
| | — |
| 28 |
| | 33 |
|
| Accounts payable – affiliates | 75 |
| | 88 |
| 6 |
| | 13 |
|
| Other current liabilities | 22 |
| | 52 |
| 27 |
| | 17 |
|
| Total current liabilities | 412 |
| | 725 |
| 444 |
| | 570 |
|
| Long-term debt | 694 |
| | — |
| 696 |
| | 694 |
|
| Pension and other postretirement benefits | 33 |
| | 47 |
| 37 |
| | 45 |
|
| Other deferred credits and liabilities | 81 |
| | 81 |
| 87 |
| | 83 |
|
| Total liabilities | 1,220 |
| | 853 |
| 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 | 5,616 |
| | 5,617 |
| 5,540 |
| | 5,556 |
|
| Retained earnings | 1,331 |
| | 1,103 |
| 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (3 | ) | | (9 | ) | (18 | ) | | (23 | ) |
| Total shareholders’ equity | 6,946 |
| | 6,713 |
| 7,184 |
| | 7,103 |
|
| Total liabilities and shareholders’ equity | $ | 8,166 |
| | $ | 7,566 |
| $ | 8,448 |
| | $ | 8,495 |
|
| | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2015, 2014, and 2013 | |
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) | | 2015 | | 2014 | | 2013 | | 2017 | | 2016 | | 2015 |
| Net cash flows provided by operating activities | | $ | 537 |
| | $ | 514 |
| | $ | 453 |
| | $ | 454 |
| | $ | 483 |
| | $ | 551 |
|
| Cash flows from investing activities: | | | | | | | | | | | | |
| Money pool advances, net | | 55 |
| | 279 |
| | (371 | ) | | 14 |
| | (27 | ) | | 55 |
|
| Notes receivable – affiliates, net | | (96 | ) | | (134 | ) | | (23 | ) | |
| Notes receivable – ATXI, net | | | 275 |
| | (60 | ) | | (96 | ) |
| Investments in subsidiaries | | (509 | ) | | (280 | ) | | (50 | ) | | (151 | ) | | (123 | ) | | (509 | ) |
| Distributions from subsidiaries | | — |
| | 215 |
| | 1 |
| |
| Proceeds from note receivable – Marketing Company | | 20 |
| | 95 |
| | 6 |
| |
| Contributions to note receivable – Marketing Company | | (8 | ) | | (89 | ) | | (5 | ) | |
| Other | | (24 | ) | | (12 | ) | | (3 | ) | | 6 |
| | 2 |
| | (12 | ) |
| Net cash flows provided by (used in) investing activities | | (562 | ) | | 74 |
| | (445 | ) | | 144 |
| | (208 | ) | | (562 | ) |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Dividends on common stock | | (402 | ) | | (390 | ) | | (388 | ) | | (431 | ) | | (416 | ) | | (402 | ) |
| Short-term debt, net | | (284 | ) | | 217 |
| | 368 |
| | (124 | ) | | 206 |
| | (284 | ) |
| Money pool borrowings, net | | 14 |
| | — |
| | — |
| | (5 | ) | | 19 |
| | 14 |
|
| Maturities of long-term debt | | — |
| | (425 | ) | | — |
| |
| Issuances of long-term debt | | 700 |
| | — |
| | — |
| | — |
| | — |
| | 700 |
|
| Capital issuance costs | | (6 | ) | | — |
| | — |
| |
| Other | | 2 |
| | — |
| | — |
| |
| Debt issuance costs | | | — |
| | — |
| | (6 | ) |
| Share-based payments | | | (39 | ) | | (83 | ) | | (12 | ) |
| Net cash flows provided by (used in) financing activities | | 24 |
| | (598 | ) | | (20 | ) | | (599 | ) | | (274 | ) | | 10 |
|
| Net change in cash and cash equivalents | | $ | (1 | ) | | $ | (10 | ) | | $ | (12 | ) | | $ | (1 | ) | | $ | 1 |
| | $ | (1 | ) |
| Cash and cash equivalents at beginning of year | | 1 |
| | 11 |
| | 23 |
| | 1 |
| | — |
| | 1 |
|
| Cash and cash equivalents at end of year | | $ | — |
| | $ | 1 |
| | $ | 11 |
| | $ | — |
| | $ | 1 |
| | $ | — |
|
| | | | | | | | | | | | | |
| Cash dividends received from consolidated subsidiaries | | $ | 575 |
| | $ | 340 |
| | $ | 570 |
| | $ | 362 |
| | $ | 465 |
| | $ | 575 |
|
| | | | | | | | | | | | | |
| Noncash investing activity – divestiture | | $ | — |
| | $ | — |
| | $ | 494 |
| |
| Noncash investing activity – investments in subsidiaries | | (38 | ) | | (19 | ) | | — |
| | — |
| | — |
| | (38 | ) |
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 20152017
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. In accordance with authoritative accounting guidance, Ameren Corporation (parent company only) has accounted for wholly ownedits 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.
Accounting Changes and Other Matters
Presentation of Debt Issuance Costs
During 2015, the FASB issued authoritative accounting guidance requiring debt issuance costs to be presented as a reduction to the associated debt liability. Previously, debt issuance costs were presented in "Other assets" on Ameren Corporation's (parent company only) balance sheet. Ameren Corporation (parent company only) early adopted this standard in 2015. Retrospective application of the new guidance had no impact on Ameren Corporation's (parent company only) balance sheet at December 31, 2014. See Note 513 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.
Balance Sheet Classification of Deferred Income Taxes
During 2015, the FASB issued authoritative accounting guidance requiring all deferred tax assets and liabilities, along with any related valuation allowances, to be classified as noncurrent on the balance sheet. Previously, the current portion of deferred taxes was presented as
"Current accumulated deferred income taxes, net" and the noncurrent portion of deferred taxes was presented as "Accumulated deferred income taxes, net" on Ameren Corporation's (parent company only) balance sheet. Ameren Corporation (parent company only) early adopted this standard in 2015 and applied the guidance retrospectively. At December 31, 2014, the current portion of deferred income taxes of $143 million previously presented as "Current accumulated deferred income taxes, net" on Ameren Corporation's (parent company only) balance sheet was reclassified and presented in "Accumulated deferred income taxes, net" for comparative purposes.
Additional disclosures relating to the parent company financial statements are included within the combined notes under Part II, Item 8, of this report. See Note 1 – Summary of Significant Accounting Policies and Note 14 – 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 20142015, 2016, and 2015.2017.
Ameren Corporation (parent company only) had a total of $36$46 million in guarantees outstanding, primarily for ATXI, that were not recorded on its December 31, 20152017 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
In November 2015, Ameren Corporation (parent company only) issued $350 million of 2.70% senior unsecured notes due November 15, 2020, with interest payable semiannually on May 15 and November 15 of each year, beginning May 15, 2016. Ameren (parent) received proceeds of $348 million, which were used to repay a portion of short-term debt.
In November 2015, Ameren Corporation (parent company only) issued $350 million of 3.65% senior unsecured notes due February 15, 2026, with interest payable semiannually on February 15 and August 15 of each year, beginning February 15, 2016. Ameren (parent) received proceeds of $347 million, which were used to repay a portion of short-term debt.
In May 2014, Ameren Corporation (parent company only) repaid at maturity $425 million of its 8.875% senior unsecured notes, plus accrued interest. The notes were repaid with proceeds from commercial paper issuances.
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.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
On December 2, 2013, Ameren completedSee Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for information regarding the divestiture of New AER to IPH in accordance with the transaction agreement between Amerentransactions and IPH dated March 14, 2013, as amended by a letter agreement dated December 2, 2013. As a result of the divestiture in 2013, Ameren Corporation (parent company only) recorded a pretax loss on disposal of $201 million. This charge was included within "Net Loss Attributable to Ameren Common Shareholders – Discontinued Operations" in the Ameren Corporation (parent company only) Condensed Statement of Income (Loss) and Comprehensive Income (Loss) for the year ended December 31, 2013.
During 2015, based on the completion of the IRS audit, Ameren Corporation (parent company only) removed a $53 million reserve for unrecognized tax benefits recorded in 2013 and recognized a tax benefit from discontinued operations.
NOTE 6 – INCOME TAXES
See Note 1312 – Income Taxes under Part II, Item 8, of this reportfor additional information regarding Ameren Corporation's (parent company only) uncertain tax positions.
In 2015, Ameren paid $25 million related to a previously-recorded liability pursuant to the transaction agreement between Ameren and IPH with no resulting additional impact to its results of operations.
See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information regarding the divestiture transactions and discontinued operations.
| | SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013 | |
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 |
|
| 2015 | $ | 21 |
| | $ | 33 |
| | $ | 5 |
| | $ | 40 |
| | $ | 19 |
| 21 |
| | 33 |
| | 5 |
| | 40 |
| | 19 |
|
| 2014 | 18 |
| | 36 |
| | 4 |
| | 37 |
| | 21 |
| |
| 2013 | 17 |
| | 35 |
| | 4 |
| | 38 |
| | 18 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 11 |
| | $ | (6 | ) | (c) | $ | — |
| | $ | — |
| | $ | 5 |
|
| 2016 | | 6 |
| | 7 |
| | (2 | ) | | — |
| | 11 |
|
| 2015 | $ | 10 |
| | $ | 4 |
| | $ | (8 | ) | | $ | — |
| | $ | 6 |
| 10 |
| | 4 |
| | (8 | ) | | — |
| | 6 |
|
| 2014 | 7 |
| | 3 |
| | — |
| | — |
| | 10 |
| |
| 2013 | 2 |
| | 5 |
| | — |
| | — |
| | 7 |
| |
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 7 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 7 |
|
| 2016 | | 7 |
| | 10 |
| | — |
| | 10 |
| | 7 |
|
| 2015 | $ | 8 |
| | $ | 13 |
| | $ | — |
| | $ | 14 |
| | $ | 7 |
| 8 |
| | 13 |
| | — |
| | 14 |
| | 7 |
|
| 2014 | 5 |
| | 16 |
| | — |
| | 13 |
| | 8 |
| |
| 2013 | 5 |
| | 16 |
| | — |
| | 16 |
| | 5 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2016 | | — |
| | — |
| | — |
| | — |
| | — |
|
| 2015 | $ | 1 |
| | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| 1 |
| | — |
| | (1 | ) | | — |
| | — |
|
| 2014 | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
| 2013 | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | 12 |
| | $ | 17 |
| | $ | 7 |
| | $ | 24 |
| | $ | 12 |
|
| 2016 | | 12 |
| | 22 |
| | 3 |
| | 25 |
| | 12 |
|
| 2015 | $ | 13 |
| | $ | 20 |
| | $ | 5 |
| | $ | 26 |
| | $ | 12 |
| 13 |
| | 20 |
| | 5 |
| | 26 |
| | 12 |
|
| 2014 | 13 |
| | 20 |
| | 4 |
| | 24 |
| | 13 |
| |
| 2013 | 12 |
| | 19 |
| | 4 |
| | 22 |
| | 13 |
| |
| Deferred tax valuation allowance: | | | | | | | | | | | | | | | | | | |
| 2017 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2016 | | — |
| | — |
| | — |
| | — |
| | — |
|
| 2015 | $ | 1 |
| | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| 1 |
| | — |
| | (1 | ) | | — |
| | — |
|
| 2014 | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
| 2013 | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
| |
| (a) | Amounts associated with the allowance for doubtful accounts relate to the uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act. The amounts relating to the deferred tax valuation allowance are for items that have expired and were removed from both the underlying accumulated deferred income tax account as well as the offsetting valuation account. |
| |
| (b) | Uncollectible accounts charged off, less recoveries. |
| |
| (c) | Includes an adjustment of $3 million to Ameren (parent)’s valuation allowance for certain deferred tax assets existing at December 31, 2017, for the reduction in the income tax rate. |
| |
| ITEM 16. | FORM 10-K SUMMARY |
The Ameren Companies elected not to provide a summary of the Form 10-K.
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith: |
| | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
| Articles of Incorporation/ By-Laws |
| 3.1(i) | Ameren | | Annex F to Part I of the Registration Statement on Form S-4, File No. 33-64165 |
| 3.2(i) | Ameren | | 1998 Form 10-K, Exhibit 3(i), File No. 1-14756 |
| 3.3(i) | Ameren | | April 21, 2011 Form 8-K, Exhibit 3(i), File No. 1-14756 |
| 3.4(i) | Ameren | | December 18, 2012 Form 8-K, Exhibit 3.1(i), File No. 1-14756 |
| 3.5(i) | Ameren Missouri | | 1993 Form 10-K, Exhibit 3(i), File No. 1-2967 |
| 3.6(i) | Ameren Illinois | | 2010 Form 10-K, Exhibit 3.4(i), File No. 1-3672 |
| 3.7(ii) | Ameren | | February 14, 2017 Form 8-K, Exhibit 3, File No. 1-14756 |
| 3.8(ii) | Ameren Missouri | | December 18, 2014 Form 8-K, Exhibit 3.1, File No. 1-2967 |
| 3.9(ii) | Ameren Illinois | | December 18, 2014 Form 8-K, Exhibit 3.2, File No. 1-3672 |
| Instruments Defining Rights of Security Holders, Including Indentures |
| 4.1 | Ameren | | Exhibit 4.5, File No. 333-81774 |
| 4.2 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756 |
| 4.3 | Ameren | | November 24, 2015 Form 8-K, Exhibits 4.3, 4.4 and 4.5, File No. 1-14756 |
| 4.4 | Ameren 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 | | Exhibit 4.22, File No. 333-222108 |
| 4.6 | Ameren Ameren Missouri | | Exhibit 4.23, File No. 333-222108 |
| 4.7 | Ameren Ameren Missouri | | Exhibit 4.24, File No. 333-222108 |
| 4.8 | Ameren Ameren Missouri | | Exhibit 4.25, File No. 333-222108 |
| 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 | | March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967 |
|
| | | |
| 4.15 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967 |
| 4.16 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967 |
| 4.17 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967 |
| 4.18 | Ameren Ameren Missouri | | September 23, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.19 | Ameren Ameren Missouri | | January 27, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.20 | Ameren Ameren Missouri | | July 21, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.21 | Ameren Ameren Missouri | | April 8, 2008 Form 8-K, Exhibit 4.7, File No. 1-2967 |
| 4.22 | Ameren Ameren Missouri | | June 19, 2008 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.23 | Ameren Ameren Missouri | | March 23, 2009 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.24 | Ameren Ameren Missouri | | Exhibit 4.45, File No. 333-182258 |
| 4.25 | Ameren Ameren Missouri | | September 11, 2012 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.26 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.27 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.28 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.29 | Ameren Ameren Missouri | 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 |
| 4.30 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.10, File No. 1-2967 |
| 4.31 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967 |
| 4.32 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.11, File No. 1-2967 |
| 4.33 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967 |
| 4.34 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.12, File No. 1-2967 |
| 4.35 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967 |
| 4.36 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.13, File No. 1-2967 |
| 4.37 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967 |
| 4.38 | Ameren Ameren Missouri | | Exhibit 4.48, File No. 333-182258 |
|
| | | |
| 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 | | January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.43 | Ameren Ameren Missouri | | July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.44 | Ameren Ameren Missouri | | April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967 |
| 4.45 | Ameren Ameren Missouri | | June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.46 | Ameren Ameren Missouri | | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.47 | Ameren Ameren Missouri | | September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.48 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.49 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.50 | Ameren Ameren Missouri | | June 23, 2016 Form 8-K, Exhibits 4.3, and 4.4, File No. 1-2967 |
| 4.51 | 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 |
| 4.53 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.54 | Ameren Ameren Illinois | | Exhibit 4.17, File No. 333-166095 |
| 4.55 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
| 4.56 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
| 4.57 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
| 4.58 | Ameren Ameren Illinois | Indenture of Mortgage and Deed of Trust between Ameren Illinois (successor in interest to Central Illinois Light Company and Illinois Power Company) and Deutsche Bank Trust Company Americas (formerly Bankers Trust Company), as trustee, dated as of April 1, 1933 (CILCO Mortgage), Supplemental Indenture between the same parties dated as of June 30, 1933, Supplemental Indenture between CILCO (predecessor in interest to Ameren Illinois) and the trustee, dated as of July 1, 1933, Supplemental Indenture between the same parties dated as of January 1, 1935, and Supplemental Indenture between the same parties dated as of April 1, 1940 | Exhibit B-1, Registration No. 2-1937; Exhibit B-1(a), Registration No. 2-2093; and Exhibit A, April 1940 Form 8-K, File No. 1-2732 |
| 4.59 | Ameren Ameren Illinois | | |
| 4.60 | Ameren Ameren Illinois | | |
|
| | | |
| 4.61 | Ameren Ameren Illinois | | |
| 4.62 | Ameren Ameren Illinois | | |
| 4.63 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
| 4.64 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
| 4.65 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732 |
| 4.66 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.1, File No. 1-3672 |
| 4.67 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
| 4.68 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732 |
| 4.69 | 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 |
| 4.70 | Ameren Ameren Illinois | | June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004 |
| 4.71 | Ameren Ameren Illinois | | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 |
| 4.72 | Ameren Ameren Illinois | | April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004 |
| 4.73 | Ameren Ameren Illinois | | October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
| 4.74 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.9, File No. 1-3672 |
| 4.75 | Ameren Ameren Illinois | | Exhibit 4.78, File No. 333-182258 |
| 4.76 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibit 4.5, File No. 1-3672 |
| 4.77 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
| 4.78 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
| 4.79 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
| 4.80 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 |
| 4.81 | 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 |
| 4.84 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K, Exhibit 4.5, File No. 1-14756 |
| 4.85 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
| 4.86 | Ameren Ameren Illinois | | Exhibit 4.83, File No. 333-182258 |
|
| | | |
| 4.87 | Ameren Ameren Illinois | | April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
| 4.88 | Ameren Ameren Illinois | | October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004 |
| 4.89 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.90 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.91 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.92 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.93 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 4.94 | Ameren Ameren Illinois | | December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| 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 | | |
| 10.5 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
| 10.6 | Ameren | | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 |
| 10.7 | Ameren | | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
| 10.8 | Ameren | | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756 |
| 10.9 | Ameren | | 2010 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.10 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.11 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.12 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.13 | Ameren Companies | | |
| 10.14 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.15 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.16 | Ameren Companies | | 2016 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 | | 2014 Form 10-K, Exhibit 10.24, File No. 1-14756 |
| 10.22 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.24, File No. 1-14756 |
| 10.23 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.24, File No. 1-14756 |
| 10.24 | Ameren Companies | | |
| 10.25 | Ameren Companies | | Exhibit 99, File No. 333-196515 |
| 10.26 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.31, File No. 1-14756 |
| 10.27 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.31, File No. 1-14756 |
| 10.28 | 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 | | |
| 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 | | |
|
| | | |
| 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’ 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 Contentsany long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
|
| | | | |
| | | AMEREN CORPORATION (registrant) |
| | | | |
| Date: | February 26, 201628, 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 26, 201628, 2018 |
| Warner L. Baxter | | | | |
| | | | |
| /s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer (Principal (Principal Financial Officer) | | February 26, 201628, 2018 |
| Martin J. Lyons, Jr. | | | | |
| | | | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 26, 201628, 2018 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | February 26, 201628, 2018 |
| Catherine S. Brune | | | | |
| | | | | | |
| * | | Director | | February 26, 201628, 2018 |
| J. Edward Coleman | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Ellen M. Fitzsimmons | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Rafael Flores | | | | |
| | | | | | |
| * | | Director | | February 26, 201628, 2018 |
| Walter J. Galvin | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Richard J. Harshman | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
Gayle P.W.P. W. Jackson | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| James C. Johnson | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Steven H. Lipstein | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Stephen R. Wilson | | | | |
| | | |
* | | Director | | February 26, 2016 |
Jack D. Woodard | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | February 26, 201628, 2018 |
| | Martin J. Lyons, Jr. | | | | |
| | Attorney-in-Fact | | | | |
|
| | | | |
| | | UNION ELECTRIC COMPANY (registrant) |
| | | | |
| Date: | February 26, 201628, 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 26, 201628, 2018 |
| Michael L. Moehn | | | | |
| | | | |
/s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 26, 201628, 2018 |
| Martin J. Lyons, Jr. | | | | |
| | | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 26, 201628, 2018 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | February 26, 201628, 2018 |
Daniel F. ColeMark C. Birk | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Fadi M. Diya | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
| Gregory L. Nelson | | | | |
| | | |
| * | | Director | | February 28, 2018 |
| David N. Wakeman | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | February 26, 201628, 2018 |
| | Martin J. Lyons, Jr. | | | | |
| | Attorney-in-Fact | | | | |
|
| | | | |
| | | AMEREN ILLINOIS COMPANY (registrant) |
| | | | | |
| Date: | February 26, 201628, 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 26, 201628, 2018 |
| Richard J. Mark | | | | |
| | | | |
| /s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 26, 201628, 2018 |
| Martin J. Lyons, Jr. | | | | |
| | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 26, 201628, 2018 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | February 26, 201628, 2018 |
Daniel F. ColeCraig D. Nelson | | | | |
| | | | |
| * | | Director | | February 26, 201628, 2018 |
Craig D.Gregory L. Nelson | | | | |
| | | | | | |
| * | | Director
| | February 26, 201628, 2018 |
Gregory L. NelsonDavid N. Wakeman | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | February 26, 201628, 2018 |
| | 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 | Restated Articles of Incorporation of Ameren | Annex F to Part I of the Registration Statement on Form S-4, File No. 33-64165 |
3.2(i) | Ameren | Certificate of Amendment to Ameren's Restated Articles of Incorporation filed December 14, 1998 | 1998 Form 10-K, Exhibit 3(i),
File No. 1-14756
|
3.3(i) | Ameren | Certificate of Amendment to Ameren's Restated Articles of Incorporation filed April 21, 2011 | April 21, 2011 Form 8-K, Exhibit 3(i),
File No. 1-14756
|
3.4(i) | Ameren | Certificate of Amendment to Ameren's Restated Articles of Incorporation filed December 18, 2012 | December 18, 2012 Form 8-K, Exhibit 3.1(i),
File No. 1-14756
|
3.5(i) | Ameren Missouri | Restated Articles of Incorporation of Ameren Missouri | 1993 Form 10-K, Exhibit 3(i),
File No. 1-2967
|
3.6(i) | Ameren Illinois | Restated Articles of Incorporation of Ameren Illinois | 2010 Form 10-K, Exhibit 3.4(i),
File No. 1-3672
|
3.7(ii) | Ameren | By-Laws of Ameren, as amended December 11, 2015 | December 11, 2015 Form 8-K, Exhibit 3.1,
File No. 1-14756
|
3.8(ii) | Ameren Missouri | Bylaws of Ameren Missouri, as amended December 12, 2014 | December 18, 2014 Form 8-K,
Exhibit 3.1, File No. 1-2967
|
3.9(ii) | Ameren Illinois | Bylaws of Ameren Illinois, as amended December 12, 2014 | December 18, 2014 Form 8-K,
Exhibit 3.2, File No. 1-3672
|
Instruments Defining Rights of Security Holders, Including Indentures |
4.1 | Ameren | Indenture, dated as of December 1, 2001 from Ameren to The Bank of New York Mellon Trust Company, N.A., as successor trustee, relating to senior debt securities (Ameren Indenture) | Exhibit 4.5, File No. 333-81774 |
4.2 | Ameren | First Supplemental Indenture to Ameren Senior Indenture dated as of May 19, 2008 | June 30, 2008 Form 10-Q, Exhibit 4.1,
File No. 1-14756
|
4.3 | Ameren | Ameren Indenture Company Order, dated November 24, 2015, establishing the 2.70% Senior Notes due 2020 and the 3.65% Senior Notes due 2026 (including the global notes) | 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
| Supplemental Indenture to the Ameren Missouri Mortgage dated as of July 1, 1956 | August 2, 1956 Form 8-K, Exhibit 2, File No. 1-2967 |
4.6 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated as of April 1, 1971 | April 1971 Form 8-K, Exhibit 6,
File No. 1-2967
|
4.7 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated as of February 1, 1974 | February 1974 Form 8-K, Exhibit 3,
File No. 1-2967
|
4.8 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated as of July 7, 1980 | Exhibit 4.6, File No. 2-69821 |
4.9 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated as of October 1, 1993, relative to Series 2028 | 1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
|
4.10 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated as of February 1, 2000 | 2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
|
4.11 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated August 15, 2002 | August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967
|
|
| | | |
4.12 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated March 5, 2003, relative to Series BB | March 11, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.13 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated July 15, 2003, relative to Series DD | 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 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004B (1998B) | March 31, 2004 Form 10-Q, Exhibit 4.2,
File No. 1-2967
|
4.17 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004C (1998C) | March 31, 2004 Form 10-Q, Exhibit 4.3,
File No. 1-2967
|
4.18 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004H (1992) | March 31, 2004 Form 10-Q, Exhibit 4.8,
File No. 1-2967
|
4.19 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated May 1, 2004 relative to Series FF | May 18, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.20 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2004 relative to Series GG | September 23, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.21 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated January 1, 2005 relative to Series HH | January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.22 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated July 1, 2005 relative to Series II | July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.23 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated December 1, 2005 relative to Series JJ | December 9, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.24 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated June 1, 2007 relative to Series KK | June 15, 2007 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.25 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2008 relative to Series LL | April 8, 2008 Form 8-K, Exhibit 4.7,
File No. 1-2967
|
4.26 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated June 1, 2008 relative to Series MM | June 19, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.27 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated March 1, 2009 relative to Series NN | March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.28 | Ameren
Ameren Missouri
| Supplemental Indenture to the Ameren Missouri Mortgage dated May 15, 2012 | Exhibit 4.45, File No. 333-182258 |
4.29 | 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
|
4.30 | 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
|
4.31 | 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 |
4.32 | Ameren
Ameren Missouri
| Loan Agreement, dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri, together with Indenture of Trust dated as of December 1, 1992, between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N.A. | 1992 Form 10-K, Exhibit 4.38,
File No. 1-2967
|
4.33 | Ameren
Ameren Missouri
| First Amendment, dated as of February 1, 2004, to Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.10,
File No. 1-2967
|
4.34 | Ameren
Ameren Missouri
| Series 1998A Loan Agreement, dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
|
4.35 | Ameren
Ameren Missouri
| First Amendment, dated as of February 1, 2004, to Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.11,
File No. 1-2967
|
4.36 | Ameren
Ameren Missouri
| Series 1998B Loan Agreement, dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
|
|
| | | |
4.37 | Ameren
Ameren Missouri
| First Amendment, dated as of February 1, 2004, to Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.12,
File No. 1-2967
|
4.38 | Ameren
Ameren Missouri
| Series 1998C Loan Agreement, dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967
|
4.39 | Ameren
Ameren Missouri
| First Amendment, dated as of February 1, 2004, to Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.13,
File No. 1-2967
|
4.40 | Ameren
Ameren Missouri
| Indenture, dated as of August 15, 2002, from Ameren Missouri to The Bank of New York Mellon, as successor trustee (relating to senior secured debt securities) (Ameren Missouri Indenture) | August 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-2967
|
4.41 | Ameren
Ameren Missouri
| First Supplemental Indenture to the Ameren Missouri Indenture, dated as of May 15, 2012 | Exhibit 4.48, File No. 333-182258 |
4.42 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated March 10, 2003, establishing the 5.50% Senior Secured Notes due 2034 (including the global note) | March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.43 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated July 28, 2003, establishing the 5.10% Senior Secured Notes due 2018 (including the global note) | August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.44 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated September 1, 2004, establishing the 5.10% Senior Secured Notes due 2019 (including the global note) | September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.45 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated January 27, 2005, establishing the 5.00% Senior Secured Notes due 2020 (including the global note) | January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.46 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated July 21, 2005, establishing the 5.30% Senior Secured Notes due 2037 (including the global note) | July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.47 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated December 8, 2005, establishing the 5.40% Senior Secured Notes due 2016 (including the global note) | December 9, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.48 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated June 15, 2007, establishing the 6.40% Senior Secured Notes due 2017 (including the global note) | June 15, 2007 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.49 | 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 |
4.50 | 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 |
4.51 | 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 |
4.52 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated September 11, 2012, establishing the 3.90% Senior Secured Notes due 2042 (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 |
4.53 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated April 4, 2014, establishing the 3.50% Senior Secured Notes due 2024 (including the global note) | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.54 | Ameren
Ameren Missouri
| Ameren Missouri Indenture Company Order, dated April 6, 2015, establishing the 3.65% Senior Secured Notes due 2045 (including the global note) | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.55 | Ameren
Ameren Illinois
| Indenture, dated as of December 1, 1998, from Central Illinois Public Service Company (now known as Ameren Illinois) to The Bank of New York Mellon Trust Company, N.A., as successor trustee (CIPS Indenture) | Exhibit 4.4, File No. 333-59438 |
4.56 | Ameren
Ameren Illinois
| First Supplemental Indenture to the CIPS Indenture, dated as of June 14, 2006 | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.57 | Ameren
Ameren Illinois
| Second Supplemental Indenture to the CIPS Indenture, dated as of March 1, 2010 | Exhibit 4.17, File No. 333-166095 |
4.58 | Ameren
Ameren Illinois
| Third Supplemental Indenture to the CIPS Indenture, dated as of October 1, 2010 | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
4.59 | Ameren
Ameren Illinois
| Ameren Illinois Global Note, dated October 1, 2010, representing CIPS Indenture Senior Notes, 6.125% due 2028 | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
4.60 | Ameren
Ameren Illinois
| Ameren Illinois Global Note, dated October 1, 2010, representing CIPS Indenture Senior Notes, 6.70% Series Secured Notes due 2036 | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
|
| | | |
4.61 | Ameren
Ameren Illinois
| Indenture of Mortgage and Deed of Trust between Illinois Power Company (predecessor in interest to CILCO and Ameren Illinois) and Bankers Trust Company (now known as Deutsche Bank Trust Company Americas), 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 |
4.62 | Ameren
Ameren Illinois
| Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949 | December 1949 Form 8-K, Exhibit A, File No. 1-2732 |
4.63 | Ameren
Ameren Illinois
| Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957 | July 1957 Form 8-K, Exhibit A, File No. 1-2732 |
4.64 | Ameren
Ameren Illinois
| Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966 | February 1966 Form 8-K, Exhibit A, File No. 1-2732 |
4.65 | Ameren
Ameren Illinois
| Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992 | January 30, 1992 Form 8-K, Exhibit 4(b), File No. 1-2732 |
4.66 | Ameren
Ameren Illinois
| Supplemental Indenture to the CILCO Mortgage, dated June 1, 2006 for the Series AA and BB | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
4.67 | Ameren
Ameren Illinois
| Supplemental Indenture to the CILCO Mortgage, dated as of October 1, 2010 | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
4.68 | Ameren
Ameren Illinois
| Indenture, dated as of June 1, 2006, from CILCO (predecessor in interest to Ameren Illinois) to The Bank of New York Mellon Trust Company, N.A., as successor trustee (CILCO Indenture) | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732 |
4.69 | Ameren
Ameren Illinois
| First Supplemental Indenture to the CILCO Indenture, dated October 1, 2010 | October 7, 2010 Form 8 K, Exhibit 4.1, File No. 1-3672 |
4.70 | Ameren
Ameren Illinois
| Second Supplemental Indenture to the CILCO Indenture dated as of July 21, 2011 | September 30, 2011 Form 10-Q, Exhibit 4.1,
File No. 1-3672
|
4.71 | Ameren
Ameren Illinois
| CILCO Indenture Company Order, dated June 14, 2006, establishing the 6.20% Senior Secured Notes due 2016 (including the global note) and the 6.70% Senior Secured Notes due 2036 (including the global note) | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732 |
4.72 | Ameren
Ameren Illinois
| General Mortgage Indenture and Deed of Trust, dated as of November 1, 1992 between Illinois Power Company (predecessor in interest to Ameren Illinois) 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 |
4.73 | 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 |
4.74 | 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 |
4.75 | 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 |
4.76 | 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 |
4.77 | 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 |
4.78 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of June 1, 2006, to Ameren Illinois Mortgage for Series AA | June 19, 2006 Form 8-K, Exhibit 4.13, File No. 1-3004 |
4.79 | 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 |
4.80 | 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 |
4.81 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of October 1, 2008, to Ameren Illinois Mortgage for Series DD | October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.82 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of October 1, 2010, to Ameren Illinois Mortgage for Series CIPS-AA, CIPS-BB and CIPS-CC | October 7, 2010 Form 8 K, Exhibit 4.9, File No. 1-3672 |
4.83 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of January 15, 2011, to Ameren Illinois Mortgage | Exhibit 4.78, File No. 333-182258 |
4.84 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of August 1, 2012, to Ameren Illinois Mortgage for Series EE | August 20, 2012 Form 8-K, Exhibit 4.4, File No. 1-3672 |
|
| | | |
4.85 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of December 1, 2013, to Ameren Illinois Mortgage for Series FF | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.86 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of June 1, 2014, to Ameren Illinois Mortgage for Series GG | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.87 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of December 1, 2014, to Ameren Illinois Mortgage for Series HH | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.88 | Ameren
Ameren Illinois
| Supplemental Indenture, dated as of December 1, 2015, to Ameren Illinois Mortgage for Series II | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.89 | Ameren
Ameren Illinois
| Indenture, dated as of June 1, 2006, from IP (predecessor in interest to Ameren Illinois) to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Ameren Illinois Indenture) | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.90 | Ameren
Ameren Illinois
| First Supplemental Indenture, dated as of October 1, 2010, to the Ameren Illinois Indenture for Series CIPS-AA, CIPS-BB and CIPS-CC | October 7, 2010 Form 8 K, Exhibit 4.5, File No. 1-14756 |
4.91 | Ameren
Ameren Illinois
| Second Supplemental Indenture to the Ameren Illinois Indenture dated as of July 21, 2011 | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
4.92 | Ameren
Ameren Illinois
| Third Supplemental Indenture to the Ameren Illinois Indenture dated as of May 15, 2012 | Exhibit 4.83, File No. 333-182258 |
4.93 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order, dated June 14, 2006, establishing the 6.25% Senior Secured Notes due 2016 (including the global note) | June 19, 2006 Form 8-K, Exhibit 4.7, File No. 1-3004 |
4.94 | 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 |
4.95 | 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 |
4.96 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order dated October 23, 2008, establishing the 9.75% Senior Secured Notes due 2018 (including the global note) | October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.97 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order dated August 20, 2012, establishing the 2.70% Senior Secured Notes due 2022 (including the global note) | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3004 |
4.98 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order dated December 10, 2013, establishing the 4.80% Senior Secured Notes due 2043 (including the global note) | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.99 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order dated June 30, 2014, establishing the 4.30% Senior Secured Notes due 2044 (including the global note) | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.100 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order dated December 10, 2014, establishing the 3.25% Senior Secured Notes due 2025 (including the global note) | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.101 | Ameren
Ameren Illinois
| Ameren Illinois Indenture Company Order dated December 14, 2015, establishing the 4.15% Senior Secured Notes due 2046 (including the global note) | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
Material Contracts |
10.1 | Ameren Companies | Fourth Amended Ameren Corporation System Utility Money Pool Agreement, as amended January 30, 2014 | June 30, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.2 | Ameren
Ameren Missouri
| Amended and Restated Credit Agreement, dated as of December 11, 2014, by and among Ameren, Ameren Missouri and JPMorgan Chase Bank, N.A., as agent, and the lenders party thereto. | December 11, 2014 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.3 | Ameren
Ameren Illinois
| Amended and Restated Credit Agreement, dated as of December 11, 2014, by and among Ameren, Ameren Illinois and JPMorgan Chase Bank, N.A., as agent, and the lenders party thereto. | December 11, 2014 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.4 | Ameren | *Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on October 9, 2015 and effective as of January 1, 2016 | |
10.5 | Ameren | *Ameren's Deferred Compensation Plan for Members of the Board of Directors amended and restated effective January 1, 2009, dated June 13, 2008 | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
10.6 | Ameren Companies | *Amendment dated October 12, 2009, to Ameren's Deferred Compensation Plan for Members of the Board of Directors, effective January 1, 2010 | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 |
|
| | | |
10.7 | Ameren Companies | *Amendment dated October 14, 2010, to Ameren's Deferred Compensation Plan for Members of the Board of Directors | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.8 | Ameren Companies | *Ameren's Deferred Compensation Plan as amended and restated effective January 1, 2010 | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.9 | Ameren Companies | *Amendment dated October 14, 2010 to Ameren's Deferred Compensation Plan | 2010 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.10 | Ameren Companies | *2013 Ameren Executive Incentive Plan | December 18, 2012 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.11 | Ameren Companies | *2014 Ameren Executive Incentive Plan | March 31, 2014 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.12 | Ameren Companies | *2015 Ameren Executive Incentive Plan | 2014 Form 10-K, Exhibit 10.13, File No. 1-14756 |
10.13 | Ameren Companies | *2016 Ameren Executive Incentive Plan | |
10.14 | Ameren Companies | *2013 Base Salary Table for Named Executive Officers | 2012 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.15 | Ameren Companies | *2014 Base Salary Table for Named Executive Officers | 2013 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.16 | Ameren Companies | *2015 Base Salary Table for Named Executive Officers | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.17 | Ameren Companies | *2016 Base Salary Table for Named Executive Officers | |
10.18 | Ameren Companies | *Second Amended and Restated Ameren Corporation Change of Control Severance Plan | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 |
10.19 | Ameren Companies | *First Amendment dated October 12, 2009, to the Second Amended and Restated Ameren Change of Control Severance Plan | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.20 | Ameren Companies | *Revised Schedule I to Second Amended and Restated Ameren Change of Control Severance Plan, as amended | |
10.21 | Ameren Companies | *Formula for Determining 2013 Target Performance Share Unit Awards to be Issued to Named Executive Officers | December 18, 2012 Form 8-K, Exhibit 99.1, File No. 1-14756 |
10.22 | 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 |
10.23 | Ameren Companies | *Formula for Determining 2015 Target Performance Share Unit Awards to be Issued to Named Executive Officers | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.24 | Ameren Companies | *Formula for Determining 2016 Target Performance Share Unit Awards to be Issued to Named Executive Officers | |
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 2013 pursuant to 2006 Omnibus Incentive Compensation Plan | December 18, 2012 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.27 | 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 |
10.28 | Ameren Companies | *Ameren Corporation 2014 Omnibus Incentive Compensation Plan | Exhibit 99, File No. 333-196515 |
10.29 | 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 |
10.30 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Awards Issued in 2015 pursuant to 2014 Omnibus Incentive Compensation Plan | 2014 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.31 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Awards Issued in 2016 pursuant to 2014 Omnibus Incentive Compensation Plan | |
10.32 | Ameren Companies | *Ameren Supplemental Retirement Plan amended and restated effective January 1, 2008, dated June 13, 2008 | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.33 | Ameren Companies | *First Amendment to amended and restated Ameren Supplemental Retirement Plan, dated October 24, 2008 | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 |
10.34 | Ameren
Ameren Illinois
| *CILCO Executive Deferral Plan as amended effective August 15, 1999 | 1999 Form 10-K, Exhibit 10, File No. 1-2732 |
10.35 | Ameren
Ameren Illinois
| *CILCO Executive Deferral Plan II as amended effective April 1, 1999 | 1999 Form 10-K, Exhibit 10(a), File No. 1-2732 |
10.36 | Ameren
Ameren Illinois
| *CILCO Restructured Executive Deferral Plan (approved August 15, 1999) | 1999 Form 10-K, Exhibit 10(e), File No. 1-2732 |
|
| | | |
10.37 | Ameren | *Employment and Change of Control Agreement, dated March 13, 2013, between Steven R. Sullivan, AER and Ameren | March 19, 2013 Form 8-K, Exhibit 10.4, File No. 1-14756 |
10.38 | Ameren | *Consulting Agreement between Charles D. Naslund and Ameren Services, dated March 2, 2015 | March 31, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
Statement re: Computation of Ratios |
12.1 | Ameren | Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges | |
12.2 | Ameren Missouri | Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
12.3 | Ameren Illinois | Ameren Illinois' Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
Subsidiaries of the Registrant |
21.1 | Ameren Companies | Subsidiaries of Ameren | |
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 | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois | |
31.6 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois | |
Section 1350 Certifications |
32.1 | Ameren | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren | |
32.2 | Ameren Missouri | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri | |
32.3 | Ameren Illinois | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois | |
Additional Exhibits |
99.1 | Ameren Companies | Amended and Restated Tax Allocation Agreement, dated as of November 21, 2013 | 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' 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.
