RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.

Missouri

Missouri Senate Bill 564

On June 1, 2018, Missouri Senate Bill 564 was enacted. The provision of the law applicable to the TCJA was effective immediately; the remaining provisions, including the ability to elect PISA, became effective August 28, 2018. The law required the MoPSC to authorize a reduction in Ameren Missouri’s rates to pass through the effect of the TCJA within 90 days of the law’s effective date. In July 2018, the MoPSC authorized Ameren Missouri to reduce its annual revenue requirement by $167 million and reflect that reduction in rates beginning August 1, 2018. The reduction included $74 million for the amortization of excess accumulated deferred income taxes. In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $60 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review.

Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. The rate base on which the return is calculated incorporates qualifying capital expenditures since the PISA election date, and changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes. The debt return on rate base is recognized in earnings as a reduction of “Interest Charges” until PISA deferrals are reflected in customer rates, while the equity return is recognized in earnings as “Operating Revenues – Electric” when billed to customers. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, and all approved PISA deferrals will be added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. PISA mitigates the impacts of regulatory lag between regulatory rate reviews. The remaining 15% of certain property, plant, and equipment placed in service and not eligible for recovery under PISA, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. See below for discussion of the RESRAM. Amounts deferred under PISA were immaterial as of December 31, 2018.

As a result of Ameren Missouri’s PISA election, additional provisions of Missouri law apply, including provisions limiting customer rate increases to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in the July 2018 MoPSC order. Additionally, Ameren Missouri’s electric base rates, as determined in the July 2018 MoPSC order, are frozen until April 1, 2020. Customer rates under the MEEIA, the FAC, and the RESRAM riders have not been frozen. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the 2.85% rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review will be subject to the rate cap. Any deferred overages approved for recovery will be recovered in a manner consistent with costs recovered under PISA. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the amount of deferred overage that would cause customer rates to exceed the 2.85% rate cap. Both the rate cap and PISA election are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.

Wind Generation Facilities and RESRAM

In the second quarter of 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Terra-Gen, LLC to acquire, after construction, a 400-megawatt wind generation facility, which is expected to be located in northeastern Missouri. In October 2018, the MoPSC issued an order approving a unanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. In December 2018, Ameren Missouri received FERC approval to acquire the facility after construction. A transmission interconnection agreement with the MISO for this facility is expected in the fall of 2019. Also, in October 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of EDF Renewables, Inc. to acquire, after construction, a wind generation facility of up to 157 megawatts. In February 2019, Ameren Missouri filed with the MoPSC a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. The up to 157-megawatt facility is expected to be located in northwestern Missouri. A transmission interconnection agreement with the MISO for this facility is expected in early 2020. Both facilities are expected to be completed by the end of 2020 and would help Ameren Missouri comply with the Missouri renewable energy standard. Each acquisition is subject to certain conditions, including entering into a MISO transmission interconnection agreement at an acceptable cost for each facility and obtaining FERC approval and the issuance of a certificate of convenience and necessity by the MoPSC for the up to 157-megawatt facility, as well as other customary contract terms and conditions. These agreements collectively represent approximately $1 billion in capital expenditures expected in 2020, which is included in Ameren Missouri’s Smart Energy Plan.

As a part of its May 2018 filing, Ameren Missouri requested the MoPSC to authorize a proposed RESRAM that would allow Ameren Missouri to adjust customer rates on an annual basis without a traditional regulatory rate review. In October and December 2018, the MoPSC issued orders approving the RESRAM. In January 2019, the MoOPC filed an appeal with the Missouri Court of Appeals, Western District, challenging the MoPSC’s December 2018 order allowing Ameren Missouri to recover, through the RESRAM, the 15% of capital investment not recovered under PISA. Ameren Missouri expects a decision by the end of 2019. The RESRAM is designed to mitigate the impacts of regulatory lag for the cost of compliance with renewable energy standards, including recovery of investments in wind and other renewable generation, by providing more timely recovery of costs and a return on investments not already provided for in customer rates or recovered under PISA. RESRAM regulatory assets earn carrying costs at short-term interest rates.

Renewable Choice Program

In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to elect to receive up to 100% of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election, net of changes in the market price of such energy. Based on customer contracts, the program enables Ameren Missouri to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it could own. As applicable, the addition of generation by Ameren Missouri would be subject to the issuance of a certificate of convenience and necessity by the MoPSC, obtaining transmission interconnection agreements with MISO or other RTOs, and FERC approval. Ameren Missouri anticipates finalizing customer interest and pursuing renewable energy projects to fulfill requirements in 2019. Without extension, the option to elect into the program will terminate in the third quarter of 2023.

MEEIA

In July 2018, the Missouri Supreme Court overturned a 2016 decision by the Missouri Court of Appeals, Western District, which had upheld a 2015 MoPSC order regarding the determination of a certain input used to calculate the MEEIA 2013 performance incentive, and remanded the matter to the MoPSC. In January 2019, the MoPSC issued an order approving an additional $9 million MEEIA 2013 performance incentive. Accordingly, Ameren Missouri recognized the additional performance incentive in the first quarter of 2019. 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 collected $28 million of the performance incentive over a two-year period that began in February 2017.

The MEEIA 2016 plan provides Ameren Missouri with a performance incentive to earn additional revenues by achieving certain customer energy-efficiency goals, including $27 million if 100% of the goals are achieved during the three-year period beginning March 2016, with the potential to earn more if Ameren Missouri’s energy savings exceed those goals. In September 2017, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings results for the first year of the MEEIA 2016 plan. In October 2018, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings results for the second year of the MEEIA 2016 plan. As a result of these orders and in accordance with revenue recognition guidance, Ameren Missouri recognized $5 million of revenues in the first quarter of 2018, $6 million of additional revenues in the fourth quarter of 2018, and $11 million of additional revenues in the first quarter of 2019 relating to the MEEIA 2016 performance incentive.

In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65 million per year through 2021. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100% of the goals are achieved during the period ended December 2021. Additional revenues may be earned if Ameren Missouri exceeds 100% of its energy savings goals.

2018 Natural Gas Delivery Service Regulatory Rate Review

In December 2018, Ameren Missouri filed a request with the MoPSC to increase its annual revenues for natural gas delivery service by approximately $4 million. The natural gas delivery service rate increase request was based on a 10.30% return on equity, a capital structure composed of 51.84% common equity, a rate base of $259 million, and a test year ended June 30, 2018, with certain pro-forma adjustments through the anticipated true-up date of May 31, 2019. In December 2018, the MoPSC issued an order approving a stipulation and agreement for an interim rate reduction of $2 million to reflect cost of service updates including the reduction in the federal corporate income tax rate and the amortization of excess deferred taxes as a result of the TCJA. The interim rate reduction became effective January 2, 2019, and will continue until new rates are approved by the MoPSC in this regulatory rate review.

Mark Twain Project Return on Equity Incentive Adder

In November 2018, the FERC issued an order approving a 50 basis point return on equity incentive adder for the Mark Twain project, effective as of February 14, 2018, based on the unique nature of risks involved in the project. This incentive adder is in addition to the current 50 basis point incentive adder for participation in an RTO and the total return on equity, inclusive of all incentive adders, is subject to the top of the zone of reasonableness. The impact to Ameren’s 2018 earnings was immaterial.

Illinois

IEIMA & FEJA

Under a formula ratemaking framework effective through 2022, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. The formula ratemaking framework 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. As of December 31, 2018, Ameren Illinois had recorded regulatory assets of $16 million and $54 million, including interest, to reflect its expected 2018 and its approved 2017 revenue requirement reconciliation adjustments, respectively. As of December 31, 2017, Ameren Illinois had recorded a $24 million regulatory asset to reflect its approved 2016 revenue requirement reconciliation adjustment, which was collected, with interest, from customers during 2018.

In November 2018, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $72 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2019. This order reflected an increase to the annual formula rate based on 2017 actual costs and expected net plant additions for 2018, and an increase to include the 2017 revenue requirement reconciliation adjustment. It also included a decrease for the conclusion of the 2016 revenue requirement reconciliation adjustment, which was fully collected from customers in 2018, consistent with the ICC’s December 2017 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.

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 its weighted-average cost of capital, with the equity return based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. In 2018, there were no performance-related basis point adjustments. In September 2017, the ICC issued an order approving Ameren Illinois’ implementation of the FEJA electric energy-efficiency savings targets and investments for 2018 through 2021. Ameren Illinois plans to invest approximately $100 million per year in electric energy-efficiency programs through 2023, consistent with targets established by the FEJA. The ICC 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 are collected from customers through a rider and are not included in the electric distribution formula ratemaking framework.

In June 2018, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In November 2018, the ICC issued an order that approved 2019 rates of $35 million for electric customer energy-efficiency investments, which represents an increase of $20 million from 2018 rates.

2018 Natural Gas Delivery Service Regulatory Rate Review

In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual rates for natural gas delivery service. In November 2018, the ICC issued an order approving a stipulation and agreement that resulted in an annual natural gas rate increase of $32 million, based on a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. This increase reflects the reduction in the federal statutory corporate income tax rate enacted under the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017, which collectively decreased annual rates by approximately $17 million. The new customer rates were effective in November 2018. As a result of this order, the rate base under the QIP rider was reset to zero. Ameren Illinois used a 2019 future test year in this proceeding.

Income Tax Regulatory Mechanisms

In February 2018, the ICC granted Ameren Illinois’ request, filed in January 2018, to establish a rider to reduce Ameren Illinois’ electric distribution customer rates for the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and the return of excess deferred taxes, net of the increase in state income taxes enacted in July 2017. Ameren Illinois' electric distribution customer rates were reduced as a result of the rider beginning in the first quarter of 2018. The estimated reduction of approximately $50 million per year will continue through 2019, as base rates will be adjusted to reflect the current income tax rates starting in 2020.

In April 2018, the ICC approved a rider for the difference between revenues billed under natural gas rates established 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 discussed above been in effect. The rider required Ameren Illinois to record this difference as a regulatory liability beginning January 25, 2018. Ameren Illinois’ natural gas customer rates were reduced as a result of the rider beginning in May 2018. As base rates were updated with the November 2018 natural gas rate order discussed above, a reduction of approximately $15 million will be reflected in customer rates substantially over a one-year period.

ATXI’s Illinois Rivers Project

In August 2017, the Illinois Circuit Court for Edgar County dismissed several of ATXI’s condemnation cases related to one line segment in the Illinois Rivers project. These cases had been filed to obtain easements and rights of way necessary to complete the line segment. The court found that required notice was not given to the relevant landowners during the underlying ICC proceeding. Upon appeal, in October 2018, the Illinois Supreme Court reversed the Illinois Circuit Court for Edgar County’s decision and remanded the case for further proceedings. In December 2018, the Illinois Supreme Court issued an order to stay its October 2018 ruling. In February 2019, the landowners filed an appeal with the United States Supreme Court. The October 2018 ruling is further stayed pending resolution of the appeal. Construction of the Illinois Rivers project is substantially complete. Delays associated with the condemnation proceedings or a rehearing arising from the Illinois Supreme Court’s ruling will delay the expected completion date to 2020, which is not expected to materially affect 2019 earnings. The estimated line segment capital expenditure investment is approximately $81 million, of which $38 million was invested as of December 31, 2018. The other eight line segments of the Illinois Rivers project are not affected by these proceedings.

Federal

FERC Complaint Cases

In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base return on common equity for FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity to 10.32%, 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, effective since September 2016. In 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively related to the November 2013 complaint case. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.

Since 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 FERC-regulated transmission rate base under the MISO tariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case. If approved by the FERC, it would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% 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 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 an unrelated case in which the FERC established the allowed base return on common equity methodology subsequently used in the two MISO complaint cases described above. In October 2018, the FERC issued an order addressing the remanded issues in an unrelated case. That order proposed a new methodology for determining the base return on equity and required further briefs from the participants. In November 2018, the FERC issued an order related to the February 2015 complaint case and the September 2016 final order, which required briefs from the participants to be filed in February 2019 regarding a new methodology for determining the base return on common equity and whether and how to apply the new methodology to the two MISO complaint cases. Ameren is unable to predict the ultimate impact of the proposed methodology on these complaint cases at this time. As the FERC is under no deadline to issue a final order, the timing of the issuance of the final order in the February 2015 complaint case, or any potential impact to the amounts refunded as a result of the September 2016 final order, is uncertain.

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 now superseded 12.38% allowed base return on common equity 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 in an unrelated case, as discussed above. The FERC is under no deadline to issue an order on this motion.

As of December 31, 2018, Ameren and Ameren Illinois had recorded current regulatory liabilities of $44 million and $26 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reduction in the FERC-allowed base return on common equity would be material to its results of operations, financial position, or liquidity.

FERC Federal Income Tax Proceeding and Formula Rate Change

In March 2018, the FERC granted a request filed in February 2018 by MISO transmission owners with forward-looking rate formulas, including Ameren Illinois and ATXI, to allow revisions to their 2018 electric transmission rates to reflect the effect of the reduction in federal income taxes enacted under the TCJA. Ameren Illinois and ATXI’s 2018 electric transmission rates were reduced by $27 million and $23 million, respectively.

In May 2018, the FERC accepted Ameren Illinois, and ATXI’s tariff filings to change the formula rate calculation. The change allows for the recovery or refund of both excess deferred taxes resulting from tax law or rate changes and the effect of permanent income tax differences and were reflected in Ameren Illinois’ and ATXI’s electric transmission rates starting in January 2019.

Regulatory Assets and Liabilities

The following table presents our regulatory assets and regulatory liabilities at December 31, 2018 and 2017:



	2018									2017
	Ameren Missouri			Ameren Illinois			Ameren				Ameren Missouri			Ameren Illinois			Ameren
Regulatory assets:
Under-recovered FAC^(a)	$	3		$	—		$	3			$	47		$	—		$	47
Under-recovered PGA^(b)	—			7			7				1			13			14
MTM derivative losses^(c)	19			197			216				12			217			229
IEIMA revenue requirement reconciliation adjustment^(d)(e)	—			70			70				—			78			78
FERC revenue requirement reconciliation adjustment^(f)	—			16			30				—			25			37
Under-recovered VBA rider^(g)	—			—			—				—			15			15
Pension and postretirement benefit costs^(h)	103			149			252				84			215			299
Income taxes⁽ⁱ⁾	119			68			185				139			56			197
Callaway costs^(e)(j)	22			—			22				25			—			25
Unamortized loss on reacquired debt^(k)	58			40			98				61			49			110
Environmental cost riders^(l)	—			148			148				—			173			173
Storm costs^(e)(m)	—			13			13				—			10			10
Demand-side costs before the MEEIA implementation^(e)(n)	5			—			5				11			—			11
Workers’ compensation claims^(o)	4			7			11				5			7			12
Construction accounting for pollution control equipment^(e)(p)	16			—			16				18			—			18
Solar rebate program^(e)(q)	14			—			14				31			—			31
FEJA energy-efficiency riders^(e)(r)	—			136			136				—			41			41
Other	17			18			35				17			10			27
Total regulatory assets	$	380		$	869		$	1,261			$	451		$	909		$	1,374
Less: current regulatory assets	(14		)	(110		)	(134		)		(56		)	(87		)	(144		)
Noncurrent regulatory assets	$	366		$	759		$	1,127			$	395		$	822		$	1,230
Regulatory liabilities:
Over-recovered FAC^(a)	$	34		$	—		$	34			$	4		$	—		$	4
Over-recovered Illinois electric power costs^(b)	—			12			12				—			16			16
Over-recovered PGA^(b)	7			3			10				—			1			1
Over-recovered VBA rider^(g)	—			8			8				—			—			—
MTM derivative gains^(c)	5			3			8				16			—			16
FERC revenue requirement reconciliation adjustment^(f)	—			17			19				—			—			—
Energy-efficiency riders^(s)	19			3			22				2			40			42
Estimated refund for FERC complaint case^(t)	—			26			44				—			25			42
Income taxes⁽ⁱ⁾	1,484			843			2,413				1,392			842			2,323
Asset removal costs^(u)	1,027			774			1,811				995			725			1,725
AROs^(v)	175			—			175				223			—			223
Pension and postretirement benefit costs tracker^(w)	43			—			43				35			—			35
Renewable energy credits and zero emission credits^(x)	—			102			102				—			58			58
Excess income taxes collected in 2018^(y)	60			—			60				—			—			—
Other	13			12			25				16			14			30
Total regulatory liabilities	$	2,867		$	1,803		$	4,786			$	2,683		$	1,721		$	4,515
Less: current regulatory liabilities	(68		)	(62		)	(149		)		(19		)	(92		)	$	(128	)
Noncurrent regulatory liabilities	$	2,799		$	1,741		$	4,637			$	2,664		$	1,629		$	4,387


(a)	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.


(b)	Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.


(c)	Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.


(d)	The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recovery or over-recovery will be recovered from, or refunded to, customers with interest within two years.


(e)	These assets earn a return.


(f)	Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years.


(g)	Under-recovered or over-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in rate regulatory reviews. Each year’s amount will be recovered from, or refunded to, customers from April through December of the following year.


(h)	These costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information.

(i)

The regulatory assets represent deferred income taxes that will be recovered from customers related to the equity component of allowance for funds used during construction and the effects of tax rate changes from the TCJA and the increased income tax rate in Illinois. The regulatory liabilities represent deferred income taxes that will be refunded to customers related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. The amortization periods for depreciation differences are determined in rate orders by the applicable regulators and range from 7 to 60 years. See Note 12 – Income Taxes for amounts related to the revaluation of deferred income taxes under the TCJA.


(j)	Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the original remaining life of the energy center.


(k)	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.


(l)	The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information.


(m)	Storm costs from 2015, 2016, and 2018 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred.

(n)

Demand-side costs incurred prior to implementation of the MEEIA in 2013, including the costs of developing, implementing, and evaluating customer energy-efficiency and demand response programs. The MoPSC’s March 2017 electric rate order modified certain amortization periods for these costs. Costs incurred from May 2008 through September 2008, and from January 2010 through July 2012, are being amortized over a two-year period that began in April 2017. Costs incurred from October 2008 through December 2009 are no longer being amortized as of April 2017, and a new amortization period for these costs will be determined in a future regulatory rate review. Costs incurred from August 2012 through December 2012 are being amortized over a six-year period that began in June 2015.


(o)	The period of recovery will depend on the timing of actual expenditures.


(p)	The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux energy center, currently through 2033.


(q)	Costs associated with Ameren Missouri’s solar rebate program to fulfill its renewable energy requirements. Costs incurred from 2010 to 2014 are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. Costs incurred from 2015 to 2016 are being amortized over a three-year period that began in April 2017.

(r)

Electric energy-efficiency program investment deferrals which earn a return at Ameren Illinois’ weighted-average cost of capital with the equity return based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from 8 to 12 years.

(s)

The Ameren Missouri balance relates to the MEEIA. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs, lost electric margins, and the performance incentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, and lost electric margins are incurred or any performance incentive are earned. The Ameren Illinois balance relates to a regulatory tracking mechanism to recover its electric pre-FEJA costs and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. Any under-recovery or over-recovery will be collected from, or refunded to, customers over the year following the plan year.


(t)	Estimated refunds to transmission customers related to the February 2015 FERC complaint case discussed above.


(u)	Estimated funds collected for the eventual dismantling and removal of plant retired from service, net of salvage value.


(v)	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.

(w)

A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. For costs incurred prior to August 2012, the amounts are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. For costs incurred between August 2012 and December 2014, the MoPSC’s May 2015 electric rate order directed the amortization period to occur over a five-year period that began in June 2015. For costs incurred between January 2015 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 2016, the amortization period will be determined in a future electric regulatory rate review.


(x)	Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased.


(y)	The excess amount collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review.