Rate And Regulatory Matters	6 Months Ended
Jun. 30, 2016
Public Utilities, General Disclosures [Abstract]
RATE AND REGULATORY MATTERS	RATE AND REGULATORY MATTERS Below is a summary of updates to significant regulatory proceedings and related lawsuits. See also Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. 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 impact on our results of operations, financial position, or liquidity. Missouri 2016 Electric Rate Case On July 1, 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The electric rate increase request is based on a 9.9% return on equity, a capital structure composed of 51.8% equity, a rate base of $7.2 billion, and a test year ended March 31, 2016, with certain pro-forma adjustments expected through the anticipated true-up date of December 31, 2016. The rate request includes $74 million that is primarily related to nearly $1.4 billion of gross electric infrastructure investments that have been placed into service since the true-up date in Ameren Missouri’s last electric rate case. This $74 million includes depreciation expenses of $39 million, return on rate base of $25 million, and increased property taxes of $10 million. The rate request also includes $51 million related to reduced customer sales volumes, including reductions from the idling of operations at Noranda’s aluminum smelter, and $34 million related to increases in transmission charges. Other changes in expenses reflected in the rate request include decreases in pension and other post-employment benefit plan expenses of $24 million and solar rebate expenses of $15 million, both of which are subject to regulatory tracking mechanisms; increased net energy costs, excluding the impact of reduced Noranda and other customer sales volumes, of $23 million; and increased income taxes of $15 million. As a part of its filing, Ameren Missouri requested the amortization over ten years of an estimated $81 million of lost fixed cost recovery due to lower sales volumes, as discussed below, from Noranda during the period April 2015 through May 2017. Ameren Missouri also requested continued use of its FAC and the regulatory tracking mechanisms for pension and postretirement benefits and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders. Additionally, Ameren Missouri requested the implementation of a new regulatory tracking mechanism for transmission charges and revenues. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by late April 2017 and new rates effective in late May 2017. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the requested regulatory tracking mechanisms will be approved, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect. Noranda In the first quarter of 2016, Noranda idled production at its aluminum smelter and filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. As of June 30, 2016, Ameren Missouri has been, and expects to continue to be, paid in full for its electric service provided to Noranda. 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, full recovery by Ameren Missouri of its revenue requirement has not occurred and will not occur until rates are adjusted prospectively by the MoPSC in the July 2016 electric rate case to accurately reflect Noranda’s actual sales volumes. Ameren Missouri is seeking to recover the April 2015 through May 2017 lost fixed costs caused by the lower Noranda sales volumes in its July 2016 electric rate case. Also as a result of Noranda’s idled production described above, Ameren Missouri is applying 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-tariff provision will not enable Ameren Missouri to fully recover its revenue requirement under current market conditions. MEEIA 2013 The MEEIA 2013 performance incentive allowed Ameren Missouri an opportunity 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. Ameren Missouri has not recorded any revenues associated with the MEEIA 2013 performance incentive. Ameren Missouri believes it will ultimately be found to have exceeded 100% of the customer energy efficiency goals. Therefore, regardless of the outcome of the appeal discussed below, Ameren Missouri expects to recognize revenues relating to the MEEIA 2013 performance incentive of at least $19 million in 2016. In November 2015, the MoPSC issued an order that clarified the method applied to determine an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals overturns the MoPSC’s November 2015 order, the MEEIA 2013 performance incentive will be more than the performance incentive calculated using the MoPSC’s November 2015 order. ATXI Transmission Projects The Mark Twain project is a MISO-approved 95-mile transmission line located in northeast Missouri. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. Starting construction under the certificate is subject to ATXI obtaining assents from the five counties where the line will be constructed. The Mark Twain project is expected to be completed in 2018. Extended difficulties in obtaining the assents could delay the completion date. ATXI is in the process of obtaining the assents. Illinois IEIMA Under the provisions of the IEIMA's performance-based formula rate-making framework, which currently extends through 2019, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs. Throughout 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. As of June 30, 2016, Ameren Illinois had recorded regulatory assets of $12 million, $66 million, and $58 million to reflect its expected 2016 and 2015 revenue requirement reconciliation adjustments and the approved 2014 revenue requirement reconciliation adjustment, with interest, respectively. In April 2016, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2017 rates. Pending ICC approval, and if approved as filed, Ameren Illinois’ update filing would result in a $14 million decrease in Ameren Illinois’ electric distribution service revenue requirement, beginning in January 2017. This update reflects an increase to the annual formula rate based on 2015 actual costs and expected net plant additions for 2016, an increase to include the 2015 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2014 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2016, consistent with the ICC’s December 2015 annual update filing order. As of December 31, 2015, Ameren Illinois had recorded a regulatory asset of $103 million related to the approved 2014 revenue requirement reconciliation adjustment. In July 2016, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended a decrease in the electric distribution service revenue requirement in an amount consistent with Ameren Illinois’ filing. Other intervenors to this rate proceeding have recommended additional decreases to Ameren Illinois’ electric distribution service revenue requirement. An ICC decision on the revenue requirement used for 2017 rates is expected by December 2016. 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 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 February 2015. The FERC is expected to issue a final order in the November 2013 complaint case in the fourth quarter of 2016, which will determine the allowed base return on common equity for the 15-month period ending February 2015. The final order in the November 2013 complaint case will also establish a new allowed base return on equity that will replace the current allowed base return on common equity of 12.38% for the period between the effective date of the November 2013 complaint case order and the effective date of the allowed base return on common equity established by the February 2015 complaint case, as discussed below. After 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. The February 2015 complaint case seeks a reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO tariff to 8.67%. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case that would lower the allowed base return on common equity to 9.70% and would require customer refunds to be issued for the 15-month period ending May 2016. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017, which will determine the allowed base return on common equity for the 15-month period ending May 2016. The final order in the February 2015 complaint case will also establish the allowed base return on common equity that will apply prospectively from the effective date of the February 2015 complaint case order, replacing the allowed base return on equity established by the November 2013 complaint case. On January 6, 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 6, 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 discussed above. As of June 30, 2016, Ameren and Ameren Illinois recorded current regulatory liabilities of $58 million and $39 million, respectively, to reflect the potential refunds associated with the reduced allowed base returns on common equity in the initial decisions for the November 2013 and February 2015 complaint cases. Ameren’s and Ameren Illinois’ liabilities also reflect the January 6, 2015 incentive adder discussed above. Ameren Missouri did not record a liability as of June 30, 2016, 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. Combined Construction and Operating License In 2008, Ameren Missouri filed an application with the NRC for a COL for a second nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a second nuclear unit at its existing Callaway site, and the NRC suspended review of the COL application. Prior to suspending its efforts, Ameren Missouri had capitalized $69 million related to the project. Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway site. As a result of this decision, in 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.

RATE AND REGULATORY MATTERS

Below is a summary of updates to significant regulatory proceedings and related lawsuits. See also Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. 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 impact on our results of operations, financial position, or liquidity.

Missouri

2016 Electric Rate Case

On July 1, 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The electric rate increase request is based on a 9.9% return on equity, a capital structure composed of 51.8% equity, a rate base of $7.2 billion, and a test year ended March 31, 2016, with certain pro-forma adjustments expected through the anticipated true-up date of December 31, 2016. The rate request includes $74 million that is primarily related to nearly $1.4 billion of gross electric infrastructure investments that have been placed into service since the true-up date in Ameren Missouri’s last electric rate case. This $74 million includes depreciation expenses of $39 million, return on rate base of $25 million, and increased property taxes of $10 million. The rate request also includes $51 million related to reduced customer sales volumes, including reductions from the idling of operations at Noranda’s aluminum smelter, and $34 million related to increases in transmission charges. Other changes in expenses reflected in the rate request include decreases in pension and other post-employment benefit plan expenses of $24 million and solar rebate expenses of $15 million, both of which are subject to regulatory tracking mechanisms; increased net energy costs, excluding the impact of reduced Noranda and other customer sales volumes, of $23 million; and increased income taxes of $15 million.

As a part of its filing, Ameren Missouri requested the amortization over ten years of an estimated $81 million of lost fixed cost recovery due to lower sales volumes, as discussed below, from Noranda during the period April 2015 through May 2017.

Ameren Missouri also requested continued use of its FAC and the regulatory tracking mechanisms for pension and postretirement benefits and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders. Additionally, Ameren Missouri requested the implementation of a new regulatory tracking mechanism for transmission charges and revenues.

The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by late April 2017 and new rates effective in late May 2017. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the requested regulatory tracking mechanisms will be approved, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

Noranda

In the first quarter of 2016, Noranda idled production at its aluminum smelter and filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. As of June 30, 2016, Ameren Missouri has been, and expects to continue to be, paid in full for its electric service provided to Noranda.

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, full recovery by Ameren Missouri of its revenue requirement has not occurred and will not occur until rates are adjusted prospectively by the MoPSC in the July 2016 electric rate case to accurately reflect Noranda’s actual sales volumes. Ameren Missouri is seeking to recover the April 2015 through May 2017 lost fixed costs caused by the lower Noranda sales volumes in its July 2016 electric rate case. Also as a result of Noranda’s idled production described above, Ameren Missouri is applying 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-tariff provision will not enable Ameren Missouri to fully recover its revenue requirement under current market conditions.

MEEIA 2013

The MEEIA 2013 performance incentive allowed Ameren Missouri an opportunity 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. Ameren Missouri has not recorded any revenues associated with the MEEIA 2013 performance incentive. Ameren Missouri believes it will ultimately be found to have exceeded 100% of the customer energy efficiency goals. Therefore, regardless of the outcome of the appeal discussed below, Ameren Missouri expects to recognize revenues relating to the MEEIA 2013 performance incentive of at least $19 million in 2016.

In November 2015, the MoPSC issued an order that clarified the method applied to determine an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals overturns the MoPSC’s November 2015 order, the MEEIA 2013 performance incentive will be more than the performance incentive calculated using the MoPSC’s November 2015 order.

ATXI Transmission Projects

The Mark Twain project is a MISO-approved 95-mile transmission line located in northeast Missouri. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. Starting construction under the certificate is subject to ATXI obtaining assents from the five counties where the line will be constructed. The Mark Twain project is expected to be completed in 2018. Extended difficulties in obtaining the assents could delay the completion date. ATXI is in the process of obtaining the assents.

Illinois

IEIMA

Under the provisions of the IEIMA's performance-based formula rate-making framework, which currently extends through 2019, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs. Throughout 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. As of June 30, 2016, Ameren Illinois had recorded regulatory assets of $12 million, $66 million, and $58 million to reflect its expected 2016 and 2015 revenue requirement reconciliation adjustments and the approved 2014 revenue requirement reconciliation adjustment, with interest, respectively.

In April 2016, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2017 rates. Pending ICC approval, and if approved as filed, Ameren Illinois’ update filing would result in a $14 million decrease in Ameren Illinois’ electric distribution service revenue requirement, beginning in January 2017. This update reflects an increase to the annual formula rate based on 2015 actual costs and expected net plant additions for 2016, an increase to include the 2015 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2014 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2016, consistent with the ICC’s December 2015 annual update filing order. As of December 31, 2015, Ameren Illinois had recorded a regulatory asset of $103 million related to the approved 2014 revenue requirement reconciliation adjustment. In July 2016, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended a decrease in the electric distribution service revenue requirement in an amount consistent with Ameren Illinois’ filing. Other intervenors to this rate proceeding have recommended additional decreases to Ameren Illinois’ electric distribution service revenue requirement. An ICC decision on the revenue requirement used for 2017 rates is expected by December 2016.

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 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 February 2015. The FERC is expected to issue a final order in the November 2013 complaint case in the fourth quarter of 2016, which will determine the allowed base return on common equity for the 15-month period ending February 2015. The final order in the November 2013 complaint case will also establish a new allowed base return on equity that will replace the current allowed base return on common equity of 12.38% for the period between the effective date of the November 2013 complaint case order and the effective date of the allowed base return on common equity established by the February 2015 complaint case, as discussed below.

After 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. The February 2015 complaint case seeks a reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO tariff to 8.67%. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case that would lower the allowed base return on common equity to 9.70% and would require customer refunds to be issued for the 15-month period ending May 2016. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017, which will determine the allowed base return on common equity for the 15-month period ending May 2016. The final order in the February 2015 complaint case will also establish the allowed base return on common equity that will apply prospectively from the effective date of the February 2015 complaint case order, replacing the allowed base return on equity established by the November 2013 complaint case.

On January 6, 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 6, 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 discussed above.

As of June 30, 2016, Ameren and Ameren Illinois recorded current regulatory liabilities of $58 million and $39 million, respectively, to reflect the potential refunds associated with the reduced allowed base returns on common equity in the initial decisions for the November 2013 and February 2015 complaint cases. Ameren’s and Ameren Illinois’ liabilities also reflect the January 6, 2015 incentive adder discussed above. Ameren Missouri did not record a liability as of June 30, 2016, 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.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL for a second nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a second nuclear unit at its existing Callaway site, and the NRC suspended review of the COL application. Prior to suspending its efforts, Ameren Missouri had capitalized $69 million related to the project. Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway site. As a result of this decision, in 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.