Asset Retirement Obligations
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the nine months ended September, 30
2012:
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Ameren
Missouri
(a)
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Ameren
Illinois
(b)
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Genco
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AERG
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Ameren
(a)
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Balance at December 31, 2011
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$
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328
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|
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$
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3
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|
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$
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71
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(c)
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|
$
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31
|
|
|
$
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433
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(c)
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Liabilities incurred
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|
|
-
|
|
|
|
-
|
|
|
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1
|
|
|
|
-
|
|
|
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1
|
|
|
Liabilities settled
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|
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(1
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)
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|
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(d
|
)
|
|
|
(5
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)
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|
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(d
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)
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|
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(6
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)
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Accretion in 2012
(e)
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14
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|
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(d
|
)
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3
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2
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|
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19
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Change in
estimates
(f)
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1
|
|
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(d
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)
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|
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(11
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)
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(d
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)
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(10
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)
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Balance at September 30, 2012
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$
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342
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$
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3
|
|
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$
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59
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$
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33
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|
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$
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437
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(g)
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(a)
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The nuclear decommissioning trust fund assets of $407 million and $357 million as of September 30, 2012, and December 31, 2011, respectively, were restricted
for decommissioning of the Callaway energy center.
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(b)
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Balance included in “Other deferred credits and liabilities” on the balance sheet.
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(c)
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Balance included $5 million in “Other current liabilities” on the balance sheet as of December 31, 2011.
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(d)
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Less than $1 million.
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(e)
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Accretion expense was recorded as an increase to regulatory assets at Ameren Missouri and Ameren Illinois.
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(f)
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Ameren Missouri and Genco changed their estimates for asbestos removal. The estimates for asbestos removal costs at Genco’s Hutsonville and Meredosia energy
centers decreased due to less asbestos than anticipated in the energy centers’ structures discovered during reviews made after the closure of these energy centers, and more cost efficient removal than anticipated being made possible due to the
closure of the energy centers. Additionally, Genco changed the estimates related to retirement costs for its coal combustion byproduct storage areas.
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(g)
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Balance included $8 million in “Other current liabilities” on the balance sheet as of September 30, 2012.
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Noncontrolling Interest
Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory
redemption of Ameren’s subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. Genco’s noncontrolling interest comprised the 20% of EEI not
owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco’s equity in its consolidated balance sheet. See Note 12 - Retirement Benefits for information regarding other comprehensive income and
amendments to EEI’s benefit plans.
A reconciliation of the equity changes attributable to the noncontrolling interests
at Ameren and Genco for the three and nine months ended September 30, 2012, and 2011, is shown below:
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Three Months
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Nine Months
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2012
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2011
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2012
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2011
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Ameren:
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|
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|
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|
|
|
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Noncontrolling interests, beginning of period
|
|
$
|
145
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|
|
$
|
155
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|
|
$
|
149
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|
|
$
|
154
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|
|
Net income (loss) attributable to noncontrolling interests
|
|
|
-
|
|
|
|
2
|
|
|
|
(1
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)
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|
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6
|
|
|
Dividends paid to noncontrolling interest holders
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|
|
(2
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)
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|
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(2
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)
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|
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(5
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)
|
|
|
(5
|
)
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Other comprehensive income attributable to noncontrolling interests
(a)
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|
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9
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|
|
|
-
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|
|
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9
|
|
|
|
-
|
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Noncontrolling interests, end of period
|
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$
|
152
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|
|
$
|
155
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|
|
$
|
152
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$
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155
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Genco:
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|
|
|
|
|
|
|
|
|
|
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Noncontrolling interest, beginning of period
|
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$
|
3
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|
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$
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12
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$
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7
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$
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11
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Net income (loss) attributable to noncontrolling interest
|
|
|
(2
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)
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|
|
1
|
|
|
|
(6
|
)
|
|
|
2
|
|
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Other comprehensive income attributable to noncontrolling interest
(a)
|
|
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9
|
|
|
|
-
|
|
|
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9
|
|
|
|
-
|
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Noncontrolling interest, end of period
|
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$
|
10
|
|
|
$
|
13
|
|
|
$
|
10
|
|
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$
|
13
|
|
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(a)
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Represents pension and other postretirement benefit plan activity, net of income taxes of $6, $-, $6, and $-, respectively.
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20
Merchant Generation Asset Sales in 2012
In February 2012, Ameren completed the sale of its Medina Valley energy center’s net property and plant for cash proceeds of $16
million and an additional $1 million payment at the two-year anniversary date of the sale if all terms of the sale agreement are met. Ameren recognized a $10 million pretax gain during the first quarter of 2012 from this sale. In October 2012, the
buyer of the Medina Valley energy center asserted that AER has not met all the terms of the sale agreement. AER is evaluating the buyer’s claim. The dollar amount of the asserted claim does not materially differ from the payment due at the
two-year anniversary date of the sale. Medina Valley was included in Ameren’s Merchant Generation segment results.
In
May 2012, Genco completed the sale of a building for cash proceeds of $1 million. Genco recognized a $1 million pretax loss from this sale.
In the third quarter of 2012, AERG completed various sales of land around its Duck Creek energy center for aggregate cash proceeds of $4 million. Ameren recognized a $2 million pretax gain during the
third quarter of 2012 from these sales.
EEI Employee Separation
In June 2012, EEI announced that it was reducing its workforce by 44 employees, which included both management and labor union represented
employees, in response to lower demand and prices for electricity. By the end of September 2012, the staff reduction was substantially complete. Ameren and Genco each recorded a $1 million pretax charge to earnings during the nine months ended
September 30, 2012, related to the workforce reduction. The charge was recorded to “Other operations and maintenance” expense on Ameren’s and Genco’s consolidated statements of income, and the charge was included in the
Merchant Generation segment results.
The announced employee reduction also resulted in a curtailment of EEI’s pension
and postretirement benefit plans, which are separate from Ameren’s pension and postretirement benefit plans. See Note 12 - Retirement Benefits for information regarding EEI’s plan curtailment and pension plan amendments in 2012.
NOTE 2 - RATE AND REGULATORY MATTERS
Below is a summary of 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
2009 Electric Rate Order
In November 2011, the Missouri Court of Appeals
issued a ruling that upheld the MoPSC’s January 2009 electric rate order. In March 2012, the Circuit Court of Stoddard County, Missouri released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21
million, reducing previously recorded trade accounts receivable.
2010 Electric Rate Order
In May 2012, the Cole County Circuit Court issued a ruling that upheld the MoPSC’s May 2010 electric rate order. In May 2012, the
Cole County Circuit Court released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $16 million, reducing the previously recorded trade accounts receivable.
2011 Electric Rate Order
In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million.
The MoPSC’s order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance.
In July 2012, the Missouri Court of Appeals, Western District, upheld the MoPSC’s July 2011 electric rate order. Ameren Missouri will not seek further appeal of the MoPSC’s order.
21
Pending Electric Rate Case
In February 2012, Ameren Missouri filed a request with the MoPSC to increase its annual revenue for electric service. The currently pending request, as amended in October 2012, seeks an annual revenue
increase of $323 million based on a 10.5% return on equity. The annual increase request includes $73 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the
MoPSC in its 2011 electric rate order. The annual increase request also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. In this rate case, Ameren Missouri
requested that the MoPSC approve the implementation of a storm cost tracking mechanism, as well as plant-in-service accounting treatment. The plant-in-service accounting proposal is designed to reduce the impact of regulatory lag on earnings and
future cash flows related to assets placed in service between rate cases by both accruing a return on the assets and deferring depreciation expense from their in-service dates until those capitalized costs are included in rates.
The MoPSC staff is currently recommending an increase to Ameren Missouri’s annual revenues of $210 million based on a return on
equity of 9%. The MoPSC staff opposed Ameren Missouri’s request to implement a storm cost tracking mechanism and Ameren Missouri’s plant-in-service accounting proposal. The MoPSC staff also recommended that all transmission costs currently
recovered through the FAC be recovered through base rates. Other parties also made recommendations through testimony filed in this case.
Ameren Missouri has agreed to settlements of various issues, some of which have been approved by the MoPSC and some of which are still subject to approval by the MoPSC. One of the approved settlements
will allow Ameren Missouri to retain the refund received in June 2012 from Entergy related to a power purchase agreement that existed prior to the implementation of the FAC, which did not impact Ameren Missouri’s pending request. See below
under Federal for additional information about this refund and Ameren Missouri’s power purchase agreement with Entergy.
The MoPSC has several important issues to consider in this case. Those issues include determining the appropriate return on equity,
Ameren Missouri’s request for the implementation of a storm cost tracking mechanism and plant-in-service accounting treatment, Ameren Missouri’s request for recovery of its 2011 severance costs, and whether Ameren Missouri should be able
to continue to employ its existing FAC, including all of the transmission costs currently included within the FAC, at the current 95% sharing level.
A decision by the MoPSC in this proceeding is expected in December 2012, with rates becoming effective on January 2, 2013. Ameren Missouri cannot predict the level of any electric service rate change
the MoPSC may approve 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.
MEEIA Filing
In August
2012, the MoPSC issued an order that approved a stipulation and agreement between Ameren Missouri, MoPSC staff, and other parties. The order includes megawatthour savings targets for Ameren Missouri’s energy efficiency programs as well as
associated cost recovery mechanisms and incentive awards. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over three years for energy efficiency programs. The order allows for Ameren Missouri to
collect, over the next three years, its program costs and 90% of its projected lost revenue from customers starting on the expected effective date for the pending electric service rate case, which is expected to be January 2, 2013. The
remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.
Additionally, the
order provides for an incentive award that would allow Ameren Missouri to earn additional revenues based on achievement of certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency 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 70% of its energy efficiency goals before it earns any incentive award. The recovery of
the incentive award from customers, if the energy efficiency goals are achieved, would begin after the three-year energy efficiency plan is complete and upon the effective date of an electric service rate case or potentially with the future adoption
of a rider mechanism.
The MoPSC’s order will not affect Ameren Missouri rates until these rates are included in an
electric service rate case. The impacts of the MoPSC’s order in this MEEIA filing are expected to be included in rates set under Ameren Missouri’s pending electric service rate case that was filed in February 2012. Ameren Missouri’s
pending electric service rate case includes an annual revenue increase request of $80 million related to its planned portfolio of energy efficiency programs included in its MEEIA filing.
FAC Prudence Review
Missouri law requires the MoPSC to perform prudence
reviews of Ameren Missouri’s FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its review of Ameren Missouri’s FAC for the period from March 1, 2009, to September 30, 2009. In this order, the
MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda’s load caused by a
severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri’s electric customers the
earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.
22
Ameren Missouri disagrees with the MoPSC order’s classification of these sales and
believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC’s April 2011 order. In June 2012,
the MoPSC filed an appeal of the Cole County Circuit Court’s ruling to the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded additional revenues as a result of the Cole County Circuit Court’s May 2012 ruling, as
the MoPSC’s appeal to the Missouri Court of Appeals is ongoing and a decision is not expected to be issued until 2013.
In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its
report, the MoPSC staff asked the MoPSC to direct Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated
these pretax earnings to be $26 million. Missouri law does not impose a specific deadline by which the MoPSC must complete its prudence reviews. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri’s
electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.
Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren
Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. We cannot
predict the ultimate outcome of these regulatory or judicial proceedings. If the courts ultimately rule in favor of Ameren Missouri’s position regarding the classification of the long-term partial requirements sales, Ameren Missouri would not
seek to recover from customers the sum that would be covered by the accounting authority order, if it is granted.
Illinois
IEIMA
On January 3,
2012, Ameren Illinois elected to participate in the performance-based formula ratemaking process established pursuant to the IEIMA by filing initial performance-based formula rates with the ICC. The initial filing was based on 2010 recoverable costs
and expected net plant additions for 2011 and 2012. In September 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $779 million, which is a $55 million decrease from the electric delivery
service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The rates became effective on October 19, 2012, and will be effective through the end of 2012. Ameren Illinois requested a rehearing of the initial
filing order, which the ICC denied. In October 2012, Ameren Illinois filed an appeal of the ICC order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes that the
ICC misapplied Illinois law, through including the use of an average rate base as opposed to a year-end rate base, the treatment of accumulated deferred income taxes, the method for calculating the equity portion of Ameren Illinois’ capital
structure, and the method for calculating interest on the revenue requirement reconciliation.
The ICC’s September 2012
order jeopardizes Ameren Illinois’ ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is
removed, Ameren Illinois is reducing its IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to achieve with the law. Ameren Illinois expects to reduce or defer a total of $30 million of its
previously planned 2013 electric distribution capital expenditures.
On April 20, 2012, Ameren Illinois filed a request
with the ICC to update its annual electric delivery service revenue requirement based on 2011 recoverable costs and expected net plant additions for 2012. The update filing will result in new electric delivery service rates on January 1, 2013.
The update filing, as amended in September 2012, requested an annual revenue requirement of $796 million, which would result in an annual increase of $17 million in Ameren Illinois’ revenues for electric delivery service above the amount
allowed in the ICC initial filing order. The requested increase primarily reflects higher recoverable operating expenses, higher taxes, and a higher equity portion of the capital structure offset by a lower return on equity due to decreases in the
average 30-year United States treasury bond rates. In September 2012, the ICC staff recommended a $765 million electric delivery service revenue requirement, which is $14 million below the amount allowed in the ICC initial filing order. Other
parties also made recommendations through testimony filed in Ameren Illinois’ update filing. On November 7, 2012, the administrative law judges issued a proposed order that reflected an annual revenue requirement of $764 million, which would
result in an annual decrease of $15 million in Ameren Illinois’ revenues for electric delivery service below the amount allowed in the ICC initial filing order.
23
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 that was in effect for that year. Consequently, Ameren Illinois’ 2012 electric delivery service revenues will be based on its 2012 actual recoverable costs, rate
base, and return on common equity as calculated under the IEIMA’s performance-based formula ratemaking framework. The 2012 revenue requirement under the IEIMA’s formula ratemaking framework is expected to be lower than the revenue
requirement included in both the ICC’s 2010 electric rate order and the ICC’s September 2012 order related to Ameren Illinois’ initial IEIMA filing. As a result, Ameren Illinois recorded a regulatory liability to represent its
estimate of the probable decrease in electric delivery service rates expected to be approved by the ICC to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an earned rate of return on common equity for 2012. Ameren
Illinois’ actual return on equity relating to electric delivery service cannot exceed 50 basis points above or below its allowed return. During the third quarter of 2012, Ameren Illinois’ electric delivery service return on equity was
capped at the maximum allowed return on equity based on the IEIMA formula ratemaking framework. As of September 30, 2012, Ameren Illinois recorded a cumulative regulatory liability of $35 million with a corresponding decrease in electric
revenues for electric delivery service relating to the 2012 revenue requirement reconciliation and the return on equity collar, which will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.
The IEIMA requires Ameren Illinois to obtain ICC approval of its advanced metering infrastructure deployment plan. The advanced metering
infrastructure deployment plan outlines how Ameren Illinois will comply with the IEIMA requirement to spend $360 million on smart grid assets over ten years on a cost-beneficial basis to its electric customers. In March 2012, Ameren Illinois
submitted its advanced metering infrastructure deployment plan to the ICC, and the ICC subsequently denied that plan in May 2012. The ICC ruled that Ameren Illinois’ plan did not provide enough support to prove that it was cost beneficial for
electric customers. Ameren Illinois requested and received a rehearing from the ICC. In its rehearing request, Ameren Illinois submitted a modified advance metering infrastructure deployment plan designed to address the ICC’s concerns about the
cost justification of the plan. Ameren Illinois expects the ICC will issue an order later this year. If approved, the plan targets the second quarter of 2014 to begin installation of smart meters. If an advanced metering infrastructure deployment
plan is ultimately not approved by the ICC, Ameren Illinois may be precluded from using the IEIMA’s performance-based formula rates.
Federal
Electric Transmission
Investment
In February 2012, FERC approved ATXI’s request for a forward-looking rate calculation with an annual
reconciliation adjustment, as well as ATXI’s request for the implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project and the Big Muddy River project.
In July 2012, Ameren, on behalf of its transmission affiliates, filed a request with FERC seeking transmission rate incentives for the
Spoon River project and the Mark Twain project. Both projects have been approved by MISO. Also in that filing, Ameren requested FERC to authorize Ameren Illinois’ use of a forward-looking rate calculation with an annual reconciliation
adjustment for its electric transmission projects. This forward-looking rate calculation is almost identical to the calculation FERC approved in its May 2011 order for ATXI. Ameren expects FERC to issue an order in 2012.
Ameren Missouri Power Purchase Agreement with Entergy Arkansas, Inc.
In May 2012, FERC issued an order upholding its January 2010 ruling that Entergy should not have included additional charges to Ameren Missouri under a 165-megawatt power purchase agreement. Ameren
Missouri paid Entergy the additional charges from 2007 through the expiration of the power purchase agreement on August 31, 2009. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million, with $26 million recorded as a
reduction to “Purchased power” expense and $5 million for interest recorded as “Miscellaneous income” in the statement of income. Ameren Missouri expects to refund to customers approximately $2 million of the funds received from
Entergy as such funds relate to the period when the FAC was effective and, therefore, such costs were previously included in customer rates. Consequently, in June 2012, Ameren Missouri recorded a $2 million reduction, representing Ameren
Missouri’s best estimate of its refund to customers, to its FAC under-recovered regulatory asset with a corresponding increase to expense. As noted above, Ameren Missouri, in its pending electric rate case, agreed to a settlement that will
allow it to retain the refund received in June 2012 from Entergy relating to a power purchase agreement that existed prior to the implementation of the FAC. In July 2012, Entergy filed an appeal of FERC’s order to the United States Court of
Appeals for the District of Columbia. A decision from the court is expected in 2013.
Ameren Illinois Electric Transmission Rate Refund
On July 19, 2012, FERC issued an order approving Ameren Illinois’ accounting for the Ameren Illinois Merger. As
part of this order, FERC concluded that Ameren Illinois improperly included acquisition premiums, particularly goodwill, in determining its common equity used in its electric
24
transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission services customers. The order required Ameren Illinois to make refunds to
customers for such improperly included amounts. In August 2012, Ameren Illinois filed a request for rehearing of this order. It is unknown when FERC will rule on Ameren’s rehearing request as it is under no deadline to do so. Based on Ameren
Illinois’ examination of the FERC order and its calculation of the impact on electric transmission formula rates, Ameren Illinois concluded that no refund was warranted. If Ameren Illinois were to determine that a refund to its electric
transmission customers is probable, a charge to earnings would be recorded for the refund in the period in which that determination was made.
2011 Wholesale Distribution Rate Case
In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million. These wholesale distribution revenues
are treated as a deduction from Ameren Illinois’ revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined.
Ameren Illinois has reached an agreement with four of its nine wholesale customers. The impasse with the remaining five wholesale customers has resulted in FERC litigation. An initial decision by the FERC administrative law judge is expected in
2012, and a final FERC decision may be received during 2013. We cannot predict the ultimate outcome of this proceeding, but Ameren Illinois does not expect a material impact 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 new 1,600-megawatt nuclear unit at Ameren Missouri’s existing Callaway County, Missouri, nuclear energy center site. In
2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear energy center site, and the NRC suspended review of the COL application.
In March 2012, the DOE announced the availability of $452 million of investment funds for the design, engineering, manufacturing, and
sale of American-made small modular reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse’s application for the DOE’s small modular reactor investment funds. The DOE
investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. Westinghouse submitted its application to the DOE in May 2012. The DOE is expected to issue a
decision on awarding the investment funds in 2012.
If Westinghouse is awarded DOE’s small modular reactor investment
funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor or multiple reactors at its Callaway energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear power plant at a
specific site in accordance with established laws and regulations. Obtaining a COL from the NRC does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does preserve the option to move forward in a timely
fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.
Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million.
Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal due to several factors, including the company’s capitalized investments in new nuclear energy center development of $69 million as of
September 30, 2012, the DOE investment funds that would help support the COL application, and its agreement with Westinghouse. If the DOE does not approve Westinghouse’s application for the small modular reactor investment funds, Ameren
Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.
All of Ameren Missouri’s costs incurred to license additional nuclear generation at the Callaway site will remain capitalized while management pursues options to maximize the value of its investment
in this project. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.
NOTE 3 - SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term
intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances.
25
The following table summarizes the borrowing activity and relevant interest rates under the
2010 Missouri Credit Agreement as of September 30, 2012, and excludes issued letters of credit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Missouri Credit Agreement ($800 million)
|
|
Ameren (Parent)
|
|
|
Ameren Missouri
|
|
|
Total
|
|
|
Average daily borrowings outstanding during 2012
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Outstanding credit facility borrowings at period end
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Weighted-average interest rate during 2012
|
|
|
-
|
|
|
|
4.15
|
%
|
|
|
4.15
|
%
|
|
Peak credit facility borrowings during 2012
|
|
$
|
-
|
|
|
$
|
50
|
|
|
$
|
50
|
|
|
Peak interest rate during 2012
|
|
|
-
|
|
|
|
4.15
|
%
|
|
|
4.15
|
%
|
The 2010 Illinois Credit Agreement and the 2010 Genco Credit Agreement were not utilized for borrowings
during the nine months ended September 30, 2012. As of September 30, 2012, based on letters of credit issued under the 2010 Credit Agreements, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available
to Ameren (parent), Ameren Missouri, Ameren Illinois and Genco collectively at September 30, 2012, was $2.08 billion.
Commercial Paper
At September 30, 2012, Ameren had $5 million of commercial paper outstanding, which was included in “Short-term
debt” on Ameren’s consolidated balance sheet. The average daily commercial paper balances outstanding during the nine months ended September 30, 2012, and 2011, were $58 million and $335 million, respectively. The weighted-average interest
rates during the nine months ended September 30, 2012, and 2011, were 0.93% and 0.85%, respectively. The peak short-term commercial paper balances outstanding during the nine months ended September 30, 2012, and 2011, were $229 million and $435
million, respectively. The peak interest rates during the nine months ended September 30, 2012, and 2011, were 1.25% and 1.46%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the nine months
ended September 30, 2012.
26
Indebtedness Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within
the 2010 Credit Agreements. See Note 4 – Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of these provisions.
The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including 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 obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois
Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of
incorporation. The 2010 Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur 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 2010 Credit Agreements require each of Ameren, Ameren Missouri, Ameren Illinois and Genco
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 September 30, 2012, the ratios of consolidated indebtedness to total
consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 47%, 47%, 42% and 44% for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. In addition, under the 2010 Genco Credit
Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most
recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren’s ratio as of September 30, 2012, was 4.9 to 1. Failure of a borrower to satisfy a
financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.
None of the Ameren
Companies’ credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance
with the provisions and covenants of their credit facilities at September 30, 2012
.
27
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. Separate money pools are maintained for utility and
non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.
Utility
Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and
borrowers. Ameren and AERG may participate in the utility money pool only as lenders. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the
2010 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 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. The utility
money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with
accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2012,
was 0.14% and 0.13%, respectively. There were no utility money pool borrowings during the three and nine months ended September 30, 2011.
Non-state-regulated Subsidiaries
Ameren, Ameren Services, AER, Genco, AERG, Marketing Company, 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 2010 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, except for Ameren Services, which may participate only as a borrower. The total amount available to the 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. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and
nine months ended September 30, 2012, was 0.52% and 0.64%, respectively (2011 - 0.83% and 0.89%, respectively).
See Note 8 -
Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and nine months ended September 30, 2012, and 2011.
NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS
Ameren Missouri
On September 11, 2012, Ameren Missouri issued $485 million principal amount of 3.90% senior secured notes due September 15, 2042, with interest payable semiannually on March 15 and
September 15 of each year, beginning March 15, 2013. These notes are secured by first mortgage bonds. Ameren Missouri received net proceeds of $478 million. The proceeds
28
were used, together with other available cash, to provide the funds necessary to complete Ameren Missouri’s tender offer on September 20, 2012, including the payment of interest and all
related fees and expenses, and to retire the $173 million principal amount 5.25% senior secured notes that matured in September 2012.
On September 20, 2012, Ameren Missouri completed its tender offer to purchase for cash its outstanding 6.00% senior secured notes due 2018, 6.70% senior secured notes due 2019, 5.10% senior secured
notes due 2018, and 5.10% senior secured notes due 2019. Any notes that were not tendered and purchased in the tender offer will remain outstanding and continue to be obligations of Ameren Missouri. The following table sets forth the aggregate
principal amount of each series of notes repurchased, along with certain other items of the tender offer:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Secured Notes
|
|
Principal Amount
Repurchased
|
|
|
Premium Plus Accrued
and Unpaid Interest
(a)
|
|
|
Principal Amount Outstanding
After Tender Offer
|
|
|
6.00% senior secured notes due 2018
|
|
$
|
71
|
|
|
$
|
19
|
|
|
$
|
179
|
|
|
6.70% senior secured notes due 2019
|
|
|
121
|
|
|
|
35
|
|
|
|
329
|
|
|
5.10% senior secured notes due 2018
|
|
|
1
|
|
|
|
(b
|
)
|
|
|
199
|
|
|
5.10% senior secured notes due 2019
|
|
|
56
|
|
|
|
12
|
|
|
|
244
|
|
|
(a)
|
The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million 3.90% senior
secured notes.
|
|
(b)
|
Amount is less than $1 million.
|
Ameren
Illinois
On August 20, 2012, Ameren Illinois issued $400 million principal amount of 2.70% senior secured notes due
September 1, 2022, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2013. These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $397 million. The
proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Illinois’ tender offer on August 27, 2012, including the payment of interest and all related fees and expenses, and to redeem all $51
million principal amount of 5.50% pollution control revenue bonds at par value plus accrued interest.
On August 27,
2012, Ameren Illinois completed its tender offer to purchase for cash its outstanding 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018. Any notes that were not tendered and purchased in the tender offer will remain
outstanding and continue to be obligations of Ameren Illinois. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Secured Notes
|
|
Principal Amount
Repurchased
|
|
|
Premium Plus Accrued
and Unpaid Interest
(a)
|
|
|
Principal Amount Outstanding
After Tender Offer
|
|
|
9.75% senior secured notes due 2018
|
|
$
|
87
|
|
|
$
|
36
|
|
|
$
|
313
|
|
|
6.25% senior secured notes due 2018
|
|
|
194
|
|
|
|
47
|
|
|
|
144
|
|
|
(a)
|
The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million 2.70% senior
secured notes.
|
Indenture Provisions and Other Covenants
Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to
issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, 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 and dividend
coverage ratios and bonds and preferred stock issuable for the 12 months ended September 30, 2012, at an assumed interest rate of 6% and dividend rate of 7%.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Required Interest
Coverage Ratio
(a)
|
|
|
Actual Interest
Coverage Ratio
|
|
|
Bonds Issuable
(b)
|
|
|
Required Dividend
Coverage Ratio
(c)
|
|
|
Actual Dividend
Coverage Ratio
|
|
|
Preferred Stock
Issuable
|
|
|
Ameren Missouri
|
|
|
>
2.0
|
|
|
|
4.3
|
|
|
$
|
3,651
|
|
|
|
>
2.5
|
|
|
|
113.8
|
|
|
$
|
2,175
|
|
|
Ameren Illinois
|
|
|
>
2.0
|
|
|
|
7.3
|
|
|
|
3,374
|
(d)
|
|
|
>
1.5
|
|
|
|
3.0
|
|
|
|
203
|
|
|
(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 $485 million and $645 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 IP mortgage indenture.
|
29
Ameren’s indenture does not require Ameren to comply with any quantitative financial
covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess
of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, 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, Ameren Illinois, Genco 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 meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, 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 its dividend payments on 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
committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization after the Ameren Illinois Merger and AERG distribution. As of September 30, 2012, Ameren Illinois’ ratio of common stock equity to total
capitalization was 57%.
Genco’s indenture includes provisions that require Genco to maintain certain interest coverage
and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The
following table summarizes these ratios for the 12 months ended and as of September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
Required
Ratio
|
|
|
Actual
Ratio
|
|
|
Restricted payment interest coverage
ratio
(a)
|
|
|
>
1.75
|
(a)
|
|
|
2.9
|
|
|
Additional indebtedness interest coverage
ratio
(b)
|
|
|
>
2.50
|
(b)
|
|
|
2.9
|
|
|
Additional indebtedness debt-to-capital ratio
(b)
|
|
|
<
60%
|
(b)
|
|
|
43
|
%
|
|
(a)
|
As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by
management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
|
|
(b)
|
Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary
money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Credit facility borrowings, including borrowings under the 2010 Genco Credit Agreement, and other borrowings from third-party, external
sources are included in the definition of indebtedness and are subject to these incurrence tests.
|
Genco’s
debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.
Under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if its interest
coverage ratio is less than a specified minimum or its leverage ratio is greater than a specified maximum. Based on projections as of September 30, 2012, of its operating results and cash flows, Genco expects that, by the end of the first
quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco’s indenture does not restrict intercompany borrowings from
Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control and, if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary
money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time.
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.
30
Off-Balance-Sheet Arrangements
At September 30, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases
entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
NOTE 5 - OTHER INCOME AND EXPENSES
The following table presents the components of “Other Income and Expenses” in Ameren’s, Ameren
Missouri’s, Ameren Illinois’ and Genco’s statement of income and statements of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2012, and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Ameren:
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for equity funds used during construction
|
|
$
|
9
|
|
|
$
|
10
|
|
|
$
|
26
|
|
|
$
|
25
|
|
|
Interest income on industrial development revenue bonds
|
|
|
7
|
|
|
|
7
|
|
|
|
21
|
|
|
|
21
|
|
|
Interest and dividend income
|
|
|
-
|
|
|
|
1
|
|
|
|
5
|
(b)
|
|
|
3
|
|
|
Other
|
|
|
1
|
|
|
|
-
|
|
|
|
2
|
|
|
|
2
|
|
|
Total miscellaneous income
|
|
$
|
17
|
|
|
$
|
18
|
|
|
$
|
54
|
|
|
$
|
51
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Donations
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
18
|
(c)
|
|
$
|
4
|
|
|
Other
|
|
|
4
|
|
|
|
4
|
|
|
|
11
|
|
|
|
11
|
|
|
Total miscellaneous expense
|
|
$
|
7
|
|
|
$
|
5
|
|
|
$
|
29
|
|
|
$
|
15
|
|
|
Ameren Missouri:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for equity funds used during construction
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
23
|
|
|
$
|
22
|
|
|
Interest income on industrial development revenue bonds
|
|
|
7
|
|
|
|
7
|
|
|
|
21
|
|
|
|
21
|
|
|
Interest and dividend income
|
|
|
-
|
|
|
|
-
|
|
|
|
4
|
(b)
|
|
|
1
|
|
|
Other
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
Total miscellaneous income
|
|
$
|
15
|
|
|
$
|
16
|
|
|
$
|
48
|
|
|
$
|
45
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Donations
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
7
|
|
|
$
|
3
|
|
|
Other
|
|
|
2
|
|
|
|
1
|
|
|
|
4
|
|
|
|
5
|
|
|
Total miscellaneous expense
|
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
11
|
|
|
$
|
8
|
|
|
Ameren Illinois:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for equity funds used during construction
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
Interest and dividend income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
Other
|
|
|
1
|
|
|
|
-
|
|
|
|
2
|
|
|
|
1
|
|
|
Total miscellaneous income
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Donations
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
11
|
(c)
|
|
$
|
1
|
|
|
Other
|
|
|
1
|
|
|
|
1
|
|
|
|
4
|
|
|
|
3
|
|
|
Total miscellaneous expense
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
15
|
|
|
$
|
4
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Total miscellaneous income
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
Total miscellaneous expense
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
|
(b)
|
Includes interest income relating to a refund of charges included in an expired power purchase agreement with Entergy. See Note 2 - Rate and Regulatory Matters for
additional information.
|
|
(c)
|
Includes Ameren Illinois’ one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual
donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois’ participation in the formula ratemaking process.
|
31
NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel,
electricity, and uranium. 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 coal, 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 as of September 30, 2012, and December 31,
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity (in millions, except as indicated)
|
|
|
Commodity
|
|
Accrual &
NPNS
Contracts
(a)
|
|
|
Cash Flow
Hedges
(b)
|
|
|
Other
Derivatives
(c)
|
|
|
Derivatives That
Qualify for
Regulatory Deferral
(d)
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Coal (in tons)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
|
100
|
|
|
|
116
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
-
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Genco
|
|
|
28
|
|
|
|
24
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
5
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Other
(f)
|
|
|
8
|
|
|
|
7
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
2
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Ameren
|
|
|
136
|
|
|
|
147
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
7
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Fuel oils (in gallons)
(g)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
57
|
|
|
|
53
|
|
|
Genco
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
38
|
|
|
|
27
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Other
(f)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
11
|
|
|
|
9
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Ameren
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
49
|
|
|
|
36
|
|
|
|
57
|
|
|
|
53
|
|
|
Natural gas (in mmbtu)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
|
5
|
|
|
|
8
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
2
|
|
|
|
9
|
|
|
|
23
|
|
|
|
19
|
|
|
Ameren Illinois
|
|
|
11
|
|
|
|
42
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
137
|
|
|
|
174
|
|
|
Genco
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
40
|
|
|
|
7
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Other
(f)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
-
|
|
|
|
1
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Ameren
|
|
|
16
|
|
|
|
50
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
42
|
|
|
|
17
|
|
|
|
160
|
|
|
|
193
|
|
|
Power (in megawatthours)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
|
4
|
|
|
|
1
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
2
|
|
|
|
1
|
|
|
|
11
|
|
|
|
6
|
|
|
Ameren Illinois
|
|
|
21
|
|
|
|
11
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
16
|
|
|
|
24
|
|
|
Genco
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Other
(f)
|
|
|
64
|
|
|
|
61
|
|
|
|
14
|
|
|
|
17
|
|
|
|
58
|
|
|
|
30
|
|
|
|
(2
|
)
|
|
|
(9
|
)
|
|
Ameren
|
|
|
89
|
|
|
|
73
|
|
|
|
14
|
|
|
|
17
|
|
|
|
60
|
|
|
|
31
|
|
|
|
25
|
|
|
|
21
|
|
|
Renewable energy credits
(h)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
|
3
|
|
|
|
4
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Ameren Illinois
|
|
|
12
|
|
|
|
12
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Other
(f)
|
|
|
1
|
|
|
|
1
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Ameren
|
|
|
16
|
|
|
|
17
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
Uranium (pounds in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri & Ameren
|
|
|
5,262
|
|
|
|
5,553
|
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
(e
|
)
|
|
|
215
|
|
|
|
148
|
|
32
|
(a)
|
Accrual contracts include commodity contracts that do not qualify as derivatives. Contracts through December 2017, March 2015, September 2035, May 2032,
and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively, as of September 30, 2012.
|
|
(b)
|
Contracts through December 2016 for power as of September 30, 2012.
|
|
(c)
|
Contracts through December 2015, October 2016, April 2015, and December 2016 for coal, fuel oils, natural gas, and power, respectively, as of
September 30, 2012.
|
|
(d)
|
Contracts through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively, as of
September 30, 2012.
|
|
(f)
|
Includes AERG contracts for coal and fuel oils, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.
|
|
(g)
|
Fuel oils consist of heating and crude oil.
|
|
(h)
|
A renewable energy credit is created for every one megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar, wind, and
landfill gas-generated power.
|
Authoritative guidance regarding derivative instruments requires that all
contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 - Fair Value Measurements for 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 if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with
changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the
statement of income or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income or the statement of income and
comprehensive income.
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. Ameren Missouri and Ameren Illinois believe derivative gains and losses 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.
Certain derivative contracts are entered into on a regular
basis as part of our risk management program but do not qualify for, or we do not choose to elect, the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged
or credited to the statement of income or the statement of income and comprehensive income in the period in which the change occurs.
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 the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible commodity
contracts or other items.
The following table presents the carrying value and balance sheet location of all derivative
instruments as of September 30, 2012, and December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Ameren
(a)
|
|
|
Ameren Missouri
|
|
|
Ameren Illinois
|
|
|
Genco
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
MTM derivative assets
|
|
$
|
23
|
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
|
|
Other assets
|
|
|
23
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Total assets
|
|
$
|
46
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Derivative liabilities designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
MTM derivative liabilities
|
|
$
|
2
|
|
|
$
|
(b
|
)
|
|
$
|
-
|
|
|
$
|
(b
|
)
|
|
|
|
Total liabilities
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Ameren
(a)
|
|
|
Ameren Missouri
|
|
|
Ameren Illinois
|
|
|
Genco
|
|
|
Derivative assets not designated as hedging instruments
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
MTM derivative assets
|
|
$
|
17
|
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
|
|
Other current assets
|
|
|
-
|
|
|
|
11
|
|
|
|
-
|
|
|
|
6
|
|
|
|
|
Other assets
|
|
|
6
|
|
|
|
4
|
|
|
|
-
|
|
|
|
1
|
|
|
Natural gas
|
|
MTM derivative assets
|
|
|
9
|
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
|
Other current assets
|
|
|
-
|
|
|
|
1
|
|
|
|
2
|
|
|
|
6
|
|
|
|
|
Other assets
|
|
|
2
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
Power
|
|
MTM derivative assets
|
|
|
85
|
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
|
Other current assets
|
|
|
-
|
|
|
|
25
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Other assets
|
|
|
32
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Total assets
|
|
$
|
151
|
|
|
$
|
45
|
|
|
$
|
2
|
|
|
$
|
14
|
|
|
Derivative liabilities not designated as hedging instruments
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
MTM derivative liabilities
|
|
$
|
6
|
|
|
$
|
(b
|
)
|
|
$
|
-
|
|
|
$
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
4
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
Fuel oils
|
|
MTM derivative liabilities
|
|
|
1
|
|
|
|
(b
|
)
|
|
|
-
|
|
|
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
3
|
|
|
|
1
|
|
|
|
-
|
|
|
|
2
|
|
|
Natural gas
|
|
MTM derivative liabilities
|
|
|
71
|
|
|
|
(b
|
)
|
|
|
59
|
|
|
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
8
|
|
|
|
-
|
|
|
|
4
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
54
|
|
|
|
9
|
|
|
|
45
|
|
|
|
-
|
|
|
Power
|
|
MTM derivative liabilities
|
|
|
74
|
|
|
|
(b
|
)
|
|
|
19
|
|
|
|
(b
|
)
|
|
|
|
MTM derivative liabilities - affiliates
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
59
|
|
|
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
9
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
111
|
|
|
|
2
|
|
|
|
87
|
|
|
|
-
|
|
|
Uranium .
|
|
MTM derivative liabilities
|
|
|
1
|
|
|
|
(b
|
)
|
|
|
-
|
|
|
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
1
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Total liabilities
|
|
$
|
326
|
|
|
$
|
32
|
|
|
$
|
269
|
|
|
$
|
14
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
MTM derivative assets
|
|
$
|
8
|
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
|
|
Other assets
|
|
|
16
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Total assets
|
|
$
|
24
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Derivative liabilities designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
Other deferred credits and liabilities
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
Total liabilities
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Derivative assets not designated as hedging instruments
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
MTM derivative assets
|
|
$
|
29
|
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
|
|
Other current assets
|
|
|
-
|
|
|
|
17
|
|
|
|
-
|
|
|
|
10
|
|
|
|
|
Other assets
|
|
|
8
|
|
|
|
6
|
|
|
|
-
|
|
|
|
1
|
|
|
Natural gas
|
|
MTM derivative assets
|
|
|
6
|
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
|
Other current assets
|
|
|
-
|
|
|
|
2
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
Other assets
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
Power
|
|
MTM derivative assets
|
|
|
72
|
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
|
Other current assets
|
|
|
-
|
|
|
|
30
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Other assets
|
|
|
99
|
|
|
|
-
|
|
|
|
77
|
|
|
|
-
|
|
|
|
|
Total assets
|
|
$
|
214
|
|
|
$
|
55
|
|
|
$
|
79
|
|
|
$
|
13
|
|
|
Derivative liabilities not designated as hedging instruments
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
MTM derivative liabilities
|
|
$
|
2
|
|
|
$
|
(b
|
)
|
|
$
|
-
|
|
|
$
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
Natural gas
|
|
MTM derivative liabilities
|
|
|
106
|
|
|
|
(b
|
)
|
|
|
90
|
|
|
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
13
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
92
|
|
|
|
13
|
|
|
|
79
|
|
|
|
-
|
|
|
Power
|
|
MTM derivative liabilities
|
|
|
53
|
|
|
|
(b
|
)
|
|
|
9
|
|
|
|
(b
|
)
|
|
|
|
MTM derivative liabilities - affiliates
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
200
|
|
|
|
(b
|
)
|
|
|
|
Other current liabilities
|
|
|
-
|
|
|
|
9
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Other deferred credits and liabilities
|
|
|
26
|
|
|
|
-
|
|
|
|
8
|
|
|
|
-
|
|
|
Uranium
|
|
Other deferred credits and liabilities
|
|
|
1
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
Total liabilities
|
|
$
|
280
|
|
|
$
|
37
|
|
|
$
|
386
|
|
|
$
|
3
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
|
(b)
|
Balance sheet line item not applicable to registrant.
|
|
(c)
|
Includes derivatives subject to regulatory deferral.
|
34
The following table presents the cumulative amount of pretax net gains (losses) on all
derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of September 30, 2012, and December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren
|
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
Other
(a)
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative gains (losses) deferred in accumulated OCI:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power derivative contracts
(b)
|
|
$
|
44
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
44
|
|
|
Interest rate derivative contracts
(c)(d)
|
|
|
(8
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(8
|
)
|
|
|
-
|
|
|
Cumulative gains (losses) deferred in regulatory liabilities or assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils derivative contracts
(e)
|
|
|
10
|
|
|
|
10
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Natural gas derivative contracts
(f)
|
|
|
(117
|
)
|
|
|
(15
|
)
|
|
|
(102
|
)
|
|
|
-
|
|
|
|
-
|
|
|
Power derivative contracts
(g)
|
|
|
(88
|
)
|
|
|
18
|
|
|
|
(165
|
)
|
|
|
-
|
|
|
|
59
|
|
|
Uranium derivative contracts
(h)
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative gains (losses) deferred in accumulated OCI:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power derivative contracts
(b)
|
|
$
|
19
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
19
|
|
|
Interest rate derivative contracts
(c)(d)
|
|
|
(8
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(8
|
)
|
|
|
-
|
|
|
Cumulative gains (losses) deferred in regulatory liabilities or assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils derivative contracts
(e)
|
|
|
19
|
|
|
|
19
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Natural gas derivative contracts
(f)
|
|
|
(191
|
)
|
|
|
(24
|
)
|
|
|
(167
|
)
|
|
|
-
|
|
|
|
-
|
|
|
Power derivative contracts
(g)
|
|
|
81
|
|
|
|
21
|
|
|
|
(140
|
)
|
|
|
-
|
|
|
|
200
|
|
|
Uranium derivative contracts
(h)
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
(a)
|
Includes amounts for Marketing Company and intercompany eliminations.
|
|
(b)
|
Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2016 as of
September 30, 2012. Based on market prices at September 30, 2012, net pre-tax unrealized gains of $21 million is expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. However, the actual
amount reclassified from accumulated OCI could vary due to future changes in market prices.
|
|
(c)
|
Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps covered the first
10 years of debt that has a 30-year maturity, and the gain in OCI was amortized over a 10-year period that began in June 2002. The balance of the gain was fully amortized as of June 30, 2012. The carrying value at December 31, 2011, was
less than $1 million.
|
|
(d)
|
Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks
associated with Genco’s April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at September, 2012, and December 31, 2011, was a loss of $8 million
and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
|
|
(e)
|
Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal
through October 2015 as of September 30, 2012. Current gains deferred as regulatory liabilities include $9 million and $9 million at Ameren and Ameren Missouri as of September 30, 2012, respectively. Current losses deferred as regulatory
assets include $1 million and $1 million at Ameren and Ameren Missouri as of September 30, 2012, respectively.
|
|
(f)
|
Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017 at Ameren and
Ameren Missouri and through October 2016 at Ameren Illinois, in each case as of September 30, 2012. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of
September 30, 2012. Current losses deferred as regulatory assets include $67 million, $8 million, and $59 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 30, 2012.
|
|
(g)
|
Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren
Illinois and through December 2015 at Ameren Missouri, in each case as of September 30, 2012. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri, respectively, as of
September 30, 2012. Current losses deferred as regulatory assets include $26 million, $8 million, and $78 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of September 30, 2012.
|
|
(h)
|
Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through
September 2014 as of September 30, 2012. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of September 30, 2012, respectively.
|
35
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 and 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 trading and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting 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 trading and netting agreements: (1) 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 trading and netting agreements allow the counterparties to net settle sale and purchase
transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.
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 one of eight groupings according to the
primary business in which each engages. The following table presents the maximum exposure, as of September 30, 2012, and December 31, 2011, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum
exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting
agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates
(a)
|
|
|
Coal
Producers
|
|
|
Commodity
Marketing
Companies
|
|
|
Electric
Utilities
|
|
|
Financial
Companies
|
|
|
Municipalities/
Cooperatives
|
|
|
Oil and Gas
Companies
|
|
|
Retail
Companies
|
|
|
Total
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMO
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
20
|
|
|
$
|
4
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
32
|
|
|
AIC
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
Genco
|
|
|
-
|
|
|
|
6
|
|
|
|
2
|
|
|
|
-
|
|
|
|
5
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
16
|
|
|
Other
(b)
|
|
|
128
|
|
|
|
4
|
|
|
|
39
|
|
|
|
10
|
|
|
|
18
|
|
|
|
362
|
(c)
|
|
|
1
|
|
|
|
90
|
|
|
|
652
|
|
|
Ameren
|
|
$
|
128
|
|
|
$
|
10
|
|
|
$
|
45
|
|
|
$
|
14
|
|
|
$
|
44
|
|
|
$
|
366
|
|
|
$
|
5
|
|
|
$
|
90
|
|
|
$
|
702
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMO
|
|
$
|
1
|
|
|
$
|
35
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
26
|
|
|
$
|
4
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
71
|
|
|
AIC
|
|
|
-
|
|
|
|
-
|
|
|
|
84
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
85
|
|
|
Genco
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
6
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
13
|
|
|
Other
(b)
|
|
|
275
|
|
|
|
1
|
|
|
|
3
|
|
|
|
10
|
|
|
|
51
|
|
|
|
194
|
(c)
|
|
|
-
|
|
|
|
87
|
|
|
|
621
|
|
|
Ameren
|
|
$
|
276
|
|
|
$
|
37
|
|
|
$
|
89
|
|
|
$
|
16
|
|
|
$
|
84
|
|
|
$
|
198
|
|
|
$
|
3
|
|
|
$
|
87
|
|
|
$
|
790
|
|
|
(a)
|
Primarily comprised of Marketing Company’s exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren
level for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14—Related Party Transactions under Part II, Item 8, of the Form 10-K for additional
information on these financial contracts.
|
|
(b)
|
Includes amounts for Marketing Company, AERG, and AFS.
|
|
(c)
|
Primarily composed of Marketing Company’s exposure to NPNS contracts with terms through September 2035.
|
The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held
to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren and Marketing Company from counterparties is based on the contractual rights under the
agreements to seek collateral, as well as the maximum exposure as calculated under the individual master trading and netting agreements, was $2 million from marketing companies at September 30, 2012. Cash collateral held by Ameren and Marketing
Company was less than $1 million from retail companies at December 31, 2011. As of September 30, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million held by Ameren and Marketing
Company. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco, and Marketing Company,
respectively.
36
The following table presents the potential loss after consideration of collateral and
application of master trading and netting agreements as of September 30, 2012, and December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates
(a)
|
|
|
Coal
Producers
|
|
|
Commodity
Marketing
Companies
|
|
|
Electric
Utilities
|
|
|
Financial
Companies
|
|
|
Municipalities/
Cooperatives
|
|
|
Oil and Gas
Companies
|
|
|
Retail
Companies
|
|
|
Total
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMO
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
14
|
|
|
$
|
4
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
23
|
|
|
AIC
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
Genco
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
9
|
|
|
Other
(b)
|
|
|
126
|
|
|
|
3
|
|
|
|
32
|
|
|
|
3
|
|
|
|
16
|
|
|
|
355
|
(c)
|
|
|
1
|
|
|
|
89
|
|
|
|
625
|
|
|
Ameren
|
|
$
|
126
|
|
|
$
|
7
|
|
|
$
|
35
|
|
|
$
|
6
|
|
|
$
|
34
|
|
|
$
|
359
|
|
|
$
|
2
|
|
|
$
|
89
|
|
|
$
|
658
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMO
|
|
$
|
1
|
|
|
$
|
35
|
|
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
22
|
|
|
$
|
4
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
66
|
|
|
AIC
|
|
|
-
|
|
|
|
-
|
|
|
|
84
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
84
|
|
|
Genco
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
4
|
|
|
Other
(b)
|
|
|
273
|
|
|
|
-
|
|
|
|
3
|
|
|
|
5
|
|
|
|
42
|
|
|
|
187
|
(c)
|
|
|
-
|
|
|
|
86
|
|
|
|
596
|
|
|
Ameren
|
|
$
|
274
|
|
|
$
|
35
|
|
|
$
|
88
|
|
|
$
|
9
|
|
|
$
|
65
|
|
|
$
|
191
|
|
|
$
|
2
|
|
|
$
|
86
|
|
|
$
|
750
|
|
|
(a)
|
Primarily comprised of Marketing Company’s exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren
level for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14—Related Party Transactions under Part II, Item 8, of the Form 10-K for additional
information on these financial contracts.
|
|
(b)
|
Includes amounts for Marketing Company, AERG, and AFS.
|
|
(c)
|
Primarily composed of Marketing Company’s exposure to NPNS contracts with terms through September 2035.
|
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, or if a counterparty with
reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of September 30, 2012, and
December 31, 2011, 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 could be
required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these
agreements were triggered on September 30, 2012, or December 31, 2011, 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)
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
$
|
93
|
|
|
$
|
4
|
|
|
$
|
80
|
|
|
Ameren Illinois
|
|
|
156
|
|
|
|
75
|
|
|
|
72
|
|
|
Genco
|
|
|
53
|
|
|
|
-
|
|
|
|
38
|
|
|
Other
(c)
|
|
|
91
|
|
|
|
8
|
|
|
|
54
|
|
|
Ameren
|
|
$
|
393
|
|
|
$
|
87
|
|
|
$
|
244
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri
|
|
$
|
102
|
|
|
$
|
8
|
|
|
$
|
86
|
|
|
Ameren Illinois
|
|
|
220
|
|
|
|
96
|
|
|
|
125
|
|
|
Genco
|
|
|
55
|
|
|
|
1
|
|
|
|
58
|
|
|
Other
(c)
|
|
|
79
|
|
|
|
11
|
|
|
|
63
|
|
|
Ameren
|
|
$
|
456
|
|
|
$
|
116
|
|
|
$
|
332
|
|
|
(a)
|
Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
|
|
(b)
|
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be
posted is after consideration of the effects of such agreements.
|
|
(c)
|
Includes amounts for Marketing Company and Ameren (parent).
|
37
Cash Flow Hedges
The following table presents the pretax net gain or loss for the three and nine months ended September 30, 2012, and 2011, associated with derivative instruments designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in
OCI
(a)
|
|
|
Location of (Gain) Loss
Reclassified from
OCI into Income
(b)
|
|
(Gain)
Loss
Reclassified from
OCI into Income
(b)
|
|
|
Location of Gain (Loss)
Recognized in Income
(c)
|
|
Gain (Loss)
Recognized
in Income
(c)
|
|
|
Three Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren:
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
(2
|
)
|
|
Operating Revenues - Electric
|
|
$
|
(1
|
)
|
|
Operating Revenues - Electric
|
|
$
|
(4
|
)
|
|
Interest rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren:
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
(5
|
)
|
|
Operating Revenues - Electric
|
|
$
|
(1
|
)
|
|
Operating Revenues - Electric
|
|
$
|
(8
|
)
|
|
Interest rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren:
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
21
|
|
|
Operating Revenues - Electric
|
|
$
|
5
|
|
|
Operating Revenues - Electric
|
|
$
|
(3
|
)
|
|
Interest rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren:
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$
|
(12
|
)
|
|
Operating Revenues - Electric
|
|
$
|
1
|
|
|
Operating Revenues - Electric
|
|
$
|
(6
|
)
|
|
Interest rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
(e)
|
|
|
-
|
|
|
Interest Charges
|
|
|
(f
|
)
|
|
Interest Charges
|
|
|
-
|
|
|
(a)
|
Effective portion of gain (loss).
|
|
(b)
|
Effective portion of (gain) loss on settlements.
|
|
(c)
|
Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
|
|
(d)
|
Includes amounts from Ameren registrant and nonregistrant subsidiaries.
|
|
(e)
|
Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
|
|
(f)
|
Less than $1 million.
|
Other Derivatives
The following table represents the net change in market value for derivatives not designated as hedging instruments for
the three and nine months ended September 30, 2012 and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain
(Loss)
Recognized in Income
|
|
Gain
(Loss)
Recognized in Income
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Ameren
(a)
|
|
Coal
|
|
Operating Expenses - Fuel
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(10
|
)
|
|
$
|
-
|
|
|
|
|
Fuel oils
|
|
Operating Expenses - Fuel
|
|
|
6
|
|
|
|
(14
|
)
|
|
|
(7
|
)
|
|
|
(4
|
)
|
|
|
|
Natural gas (generation)
|
|
Operating Expenses - Fuel
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
|
Power
|
|
Operating Revenues - Electric
|
|
|
4
|
|
|
|
2
|
|
|
|
10
|
|
|
|
(5
|
)
|
|
|
|
|
|
Total
|
|
$
|
9
|
|
|
$
|
(12
|
)
|
|
$
|
(3
|
)
|
|
$
|
(9
|
)
|
|
Ameren Missouri
|
|
Natural gas (generation)
|
|
Operating Expenses - Fuel
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(1
|
)
|
|
Genco
|
|
Coal
|
|
Operating Expenses - Fuel
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(8
|
)
|
|
$
|
-
|
|
|
|
|
Fuel oils
|
|
Operating Expenses - Fuel
|
|
|
5
|
|
|
|
(10
|
)
|
|
|
(5
|
)
|
|
|
(3
|
)
|
|
|
|
Natural gas (generation)
|
|
Operating Expenses - Fuel
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
3
|
|
|
|
1
|
|
|
|
|
Power
|
|
Operating Revenues
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(3
|
)
|
|
|
|
|
|
Total
|
|
$
|
4
|
|
|
$
|
(11
|
)
|
|
$
|
(10
|
)
|
|
$
|
(5
|
)
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
38
Derivatives that Qualify for Regulatory Deferral
The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and nine
months ended September 30, 2012, and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in Regulatory
Liabilities or Regulatory Assets
|
|
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Ameren
(a)
|
|
Fuel oils
|
|
$
|
5
|
|
|
$
|
(20
|
)
|
|
$
|
(9
|
)
|
|
$
|
(4
|
)
|
|
|
|
Natural gas
|
|
|
46
|
|
|
|
(11
|
)
|
|
|
74
|
|
|
|
23
|
|
|
|
|
Power
|
|
|
(6
|
)
|
|
|
13
|
|
|
|
(169
|
)
|
|
|
103
|
|
|
|
|
Uranium
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
(3
|
)
|
|
|
|
Total
|
|
$
|
44
|
|
|
$
|
(17
|
)
|
|
$
|
(105
|
)
|
|
$
|
119
|
|
|
Ameren Missouri
|
|
Fuel oils
|
|
$
|
5
|
|
|
$
|
(20
|
)
|
|
$
|
(9
|
)
|
|
$
|
(4
|
)
|
|
|
|
Natural gas
|
|
|
6
|
|
|
|
-
|
|
|
|
9
|
|
|
|
4
|
|
|
|
|
Power
|
|
|
(6
|
)
|
|
|
(7
|
)
|
|
|
(3
|
)
|
|
|
16
|
|
|
|
|
Uranium
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
(3
|
)
|
|
|
|
Total
|
|
$
|
4
|
|
|
$
|
(26
|
)
|
|
$
|
(4
|
)
|
|
$
|
13
|
|
|
Ameren Illinois
|
|
Natural gas
|
|
$
|
40
|
|
|
$
|
(11
|
)
|
|
$
|
65
|
|
|
$
|
19
|
|
|
|
|
Power
|
|
|
56
|
|
|
|
70
|
|
|
|
(25
|
)
|
|
|
218
|
|
|
|
|
Total
|
|
$
|
96
|
|
|
$
|
59
|
|
|
$
|
40
|
|
|
$
|
237
|
|
|
(a)
|
Includes amounts for intercompany eliminations.
|
As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois entered into financial contracts with Marketing Company. These financial
contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by Ameren Illinois. Consequently, Ameren Illinois and Marketing Company record the fair
value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by Ameren Illinois and OCI by Marketing Company. In Ameren’s consolidated financial statements, all financial
statement effects of the derivative instruments entered into among affiliates were eliminated. The fair value of the financial contracts included in “MTM derivative liabilities - affiliates” on Ameren Illinois’ balance sheet totaled
$59 million and $200 million at September 30, 2012, and December 31, 2011, respectively. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
NOTE 7 - 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 1
: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and
cash equivalents and listed equity securities, such as those held in Ameren Missouri’s Nuclear Decommissioning Trust Fund.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri’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 is comprised
of 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, U.S. treasury and agency securities, and
certain over-the-counter derivative instruments, including natural gas and financial power transactions.
Fixed income
securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs
other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund
are comprised primarily of corporate bonds, asset-backed securities and U.S. 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.
39
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 of the bid/ask spreads. 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. Natural gas derivative contracts are valued based upon exchange closing prices without
significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant
unobservable adjustments.
Level 3
: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are
valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable,
including the financial contracts entered into between Ameren Illinois and Marketing Company as part of the 2007 Illinois Electric Supply Agreement. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the
market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our fair value estimation process, 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 for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
Valuation Technique(s)
|
|
Unobservable Input
|
|
Range [Weighted
Average]
|
|
|
|
|
Assets
Liabilities
|
|
|
|
|
|
Level 3 Derivative asset and liability - commodity
contracts
(a)
:
|
|
|
|
Ameren
(b)
|
|
Fuel oils
|
|
$
|
8
|
|
|
$
|
(2
|
)
|
|
Discounted cash flow
|
|
Escalation rate(%)
(c)
|
|
.25 - .70 [.56]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty credit risk(%)
(d),(e)
|
|
.12 - 9 [2]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option model
|
|
Volatilities(%)
(c)
|
|
22 - 30 [27]
|
|
|
|
Power
(f)
|
|
|
146
|
|
|
|
(174
|
)
|
|
Option model
|
|
Volatilities(%)
(d)
|
|
14 - 61 [18]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)
(d)
|
|
22 - 47 [33]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted cash flow
|
|
Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)
(d)
|
|
16 - 55 [32]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated auction price for FTRs
($/MW)
(c)
|
|
(19,671) -133,769 [166]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nodal basis
($/MWh)
(d)
|
|
(12) - 2 [(1)]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty credit risk(%)
(d),(e)
|
|
.06 - 12 [3]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren credit risk(%)
(d),(e)
|
|
2 - 4 [4]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fundamental energy production model
|
|
Estimated future gas prices ($/mmbtu)
(c)
|
|
4 - 7 [6]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract price allocation
|
|
Estimated renewable energy credit costs ($/credit)
(c)
|
|
5 - 7 [6]
|
|
|
|
|
|
|
|
|
|
|
|
Uranium
|
|
|
-
|
|
|
|
(2
|
)
|
|
Discounted cash flow
|
|
Average bid/ask consensus pricing ($/pound)
(c)
|
|
45 - 55 [47]
|
|
Ameren
Missouri
|
|
Fuel oils
|
|
$
|
7
|
|
|
$
|
(2
|
)
|
|
Discounted cash flow
|
|
Escalation rate(%)
(c)
|
|
.25 - .70 [.59]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty credit risk(%)
(d),(e)
|
|
.12 - 4 [2]
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
Valuation Technique(s)
|
|
Unobservable Input
|
|
Range
[Weighted
Average]
|
|
|
|
|
Assets
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option model
|
|
Volatilities(%)
(c)
|
|
22 - 30 [27]
|
|
|
|
Power
(f)
|
|
|
20
|
|
|
|
(5
|
)
|
|
Option model
|
|
Volatilities(%)
(d)
|
|
49 - 61 [56]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average bid/ask consensus peak and offpeak pricing - ($/MWh)
(d)
|
|
21 - 26 [22]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted cash flow
|
|
Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)
(d)
|
|
19 - 58 [35]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated auction price for FTRs ($/MW)
(c)
|
|
23 - 2,120 [139]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nodal basis ($/MWh)
(d)
|
|
(7) - (.40) [(4)]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty credit risk(%)
(d),(e)
|
|
.22 - 9 [3]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Missouri credit risk(%)
(d),(e)
|
|
2
|
|
|
|
Uranium
|
|
|
-
|
|
|
|
(2
|
)
|
|
Discounted cash flow
|
|
Average bid/ask consensus pricing ($/pound)
(c)
|
|
45 - 55 [47]
|
|
Ameren Illinois
|
|
Power
(f)
|
|
$
|
-
|
|
|
$
|
(165
|
)
|
|
Discounted cash flow
|
|
Average bid/ask consensus peak and offpeak pricing - forwards/swaps ($/MWh)
(c)
|
|
17 - 47 [27]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nodal basis ($/MWh)
(c)
|
|
(5) - (.91) [(3)]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren Illinois credit risk (%)
(d),(e)
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fundamental energy production model
|
|
Estimated future gas prices ($/mmbtu)
(c)
|
|
4 - 7 [5]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract price allocation
|
|
Estimated renewable energy credit costs
($/credit)
(c)
|
|
5 - 7 [6]
|
|
Genco
|
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
-
|
|
|
Discounted cash flow
|
|
Escalation rate
(c)
|
|
.25 - .70 [.64]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty credit risk (%)
(d),(e)
|
|
.12 - 9 [3]
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option model
|
|
Volatilities (%)
(c)
|
|
22 - 30 [24]
|
|
(a)
|
The derivative asset and liability balances are presented net of counterparty credit considerations.
|
|
(b)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
|
(c)
|
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
|
|
(d)
|
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
|
|
(e)
|
Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, Ameren Illinois, and Genco credit risk is only
applied to counterparties with derivative liability balances.
|
|
(f)
|
Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2016. Valuations beyond 2016 utilize fundamentally modeled pricing
by month for peak and off-peak.
|
In accordance with applicable authoritative accounting guidance, we consider
nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement
of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative
assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit
ratings. Ameren recorded losses totaling $1 million and $1 million in the first nine months of 2012 and 2011, respectively, related to valuation adjustments for counterparty default risk. Genco recorded losses of less than $1 million and less than
$1 million in the first nine months of 2012 and 2011, respectively, related to valuation adjustments for counterparty default risk. At September 30, 2012, the counterparty default risk (asset)/liability valuation adjustment related to
derivative contracts totaled $5 million, less than $(1) million, $9 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. At December 31, 2011, the counterparty default risk (asset)/liability
valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, $19 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.
41
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 September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
(a)
|
|
Derivative assets - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
$
|
15
|
|
|
$
|
-
|
|
|
$
|
8
|
|
|
$
|
23
|
|
|
|
|
Natural gas
|
|
|
7
|
|
|
|
4
|
|
|
|
-
|
|
|
|
11
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
17
|
|
|
|
146
|
|
|
|
163
|
|
|
|
|
Total derivative assets - commodity contracts
|
|
$
|
22
|
|
|
$
|
21
|
|
|
$
|
154
|
|
|
$
|
197
|
|
|
|
|
Nuclear Decommissioning Trust Fund
(c)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. large capitalization
|
|
|
270
|
|
|
|
-
|
|
|
|
-
|
|
|
|
270
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds
|
|
|
-
|
|
|
|
46
|
|
|
|
-
|
|
|
|
46
|
|
|
|
|
Municipal bonds
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
U.S. treasury and agency securities
|
|
|
-
|
|
|
|
78
|
|
|
|
-
|
|
|
|
78
|
|
|
|
|
Asset-backed securities
|
|
|
-
|
|
|
|
11
|
|
|
|
-
|
|
|
|
11
|
|
|
|
|
Other
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
Total Nuclear Decommissioning Trust Fund
|
|
$
|
272
|
|
|
$
|
137
|
|
|
$
|
-
|
|
|
$
|
409
|
|
|
|
|
Total Ameren
|
|
$
|
294
|
|
|
$
|
158
|
|
|
$
|
154
|
|
|
$
|
606
|
|
|
Ameren
|
|
Derivative assets - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Missouri
|
|
Fuel oils
|
|
$
|
8
|
|
|
$
|
-
|
|
|
$
|
7
|
|
|
$
|
15
|
|
|
|
|
Natural gas
|
|
|
1
|
|
|
|
1
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
8
|
|
|
|
20
|
|
|
|
28
|
|
|
|
|
Total derivative assets - commodity contracts
|
|
$
|
9
|
|
|
$
|
9
|
|
|
$
|
27
|
|
|
$
|
45
|
|
|
|
|
Nuclear Decommissioning Trust Fund
(c)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. large capitalization
|
|
|
270
|
|
|
|
-
|
|
|
|
-
|
|
|
|
270
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds
|
|
|
-
|
|
|
|
46
|
|
|
|
-
|
|
|
|
46
|
|
|
|
|
Municipal bonds
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
U.S. treasury and agency securities
|
|
|
-
|
|
|
|
78
|
|
|
|
-
|
|
|
|
78
|
|
|
|
|
Asset-backed securities
|
|
|
-
|
|
|
|
11
|
|
|
|
-
|
|
|
|
11
|
|
|
|
|
Other
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
Total Nuclear Decommissioning Trust Fund
|
|
$
|
272
|
|
|
$
|
137
|
|
|
$
|
-
|
|
|
$
|
409
|
|
|
|
|
Total Ameren Missouri
|
|
$
|
281
|
|
|
$
|
146
|
|
|
$
|
27
|
|
|
$
|
454
|
|
|
Ameren
|
|
Derivative assets - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Natural gas
|
|
$
|
-
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
Genco
|
|
Derivative assets - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
$
|
6
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
7
|
|
|
|
|
Natural gas
|
|
|
6
|
|
|
|
1
|
|
|
|
-
|
|
|
|
7
|
|
|
|
|
Total Genco
|
|
$
|
12
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
14
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren
(a)
|
|
Derivative liabilities - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
$
|
10
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
10
|
|
|
|
|
Fuel oils
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
|
|
4
|
|
|
|
|
Natural gas
|
|
|
12
|
|
|
|
113
|
|
|
|
-
|
|
|
|
125
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
13
|
|
|
|
174
|
|
|
|
187
|
|
|
|
|
Uranium
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
Total Ameren
|
|
$
|
24
|
|
|
$
|
126
|
|
|
$
|
178
|
|
|
$
|
328
|
|
|
Ameren
|
|
Derivative liabilities - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Missouri
|
|
Fuel oils
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
|
|
Natural gas
|
|
|
9
|
|
|
|
8
|
|
|
|
-
|
|
|
|
17
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
6
|
|
|
|
5
|
|
|
|
11
|
|
|
|
|
Uranium
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
Total Ameren Missouri
|
|
$
|
9
|
|
|
$
|
14
|
|
|
$
|
9
|
|
|
$
|
32
|
|
|
Ameren
|
|
Derivative liabilities - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Natural gas
|
|
$
|
-
|
|
|
$
|
104
|
|
|
$
|
-
|
|
|
$
|
104
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
-
|
|
|
|
165
|
|
|
|
165
|
|
|
|
|
Total Ameren Illinois
|
|
$
|
-
|
|
|
$
|
104
|
|
|
$
|
165
|
|
|
$
|
269
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
Genco
|
|
Derivative liabilities - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
$
|
8
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
8
|
|
|
|
|
Fuel oils
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
Natural gas
|
|
|
3
|
|
|
|
1
|
|
|
|
-
|
|
|
|
4
|
|
|
|
|
Total Genco
|
|
$
|
13
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
14
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
|
(b)
|
The derivative asset and liability balances are presented net of counterparty credit considerations.
|
|
(c)
|
Balance excludes $(2) million of receivables, payables, and accrued income, net.
|
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
(a)
|
|
Derivative assets - commodity contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
$
|
33
|
|
|
$
|
-
|
|
|
$
|
4
|
|
|
$
|
37
|
|
|
|
|
Natural gas
|
|
|
4
|
|
|
|
-
|
|
|
|
2
|
|
|
|
6
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
2
|
|
|
|
193
|
|
|
|
195
|
|
|
|
|
Total derivative assets - commodity
contracts
|
|
$
|
37
|
|
|
$
|
2
|
|
|
$
|
199
|
|
|
$
|
238
|
|
|
|
|
Nuclear Decommissioning Trust
Fund
(c)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
3
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. large capitalization
|
|
|
234
|
|
|
|
-
|
|
|
|
-
|
|
|
|
234
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds
|
|
|
-
|
|
|
|
44
|
|
|
|
-
|
|
|
|
44
|
|
|
|
|
Municipal bonds
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
U.S. treasury and agency securities
|
|
|
-
|
|
|
|
65
|
|
|
|
-
|
|
|
|
65
|
|
|
|
|
Asset-backed securities
|
|
|
-
|
|
|
|
10
|
|
|
|
-
|
|
|
|
10
|
|
|
|
|
Other
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
Total Nuclear Decommissioning Trust Fund
|
|
$
|
237
|
|
|
$
|
121
|
|
|
$
|
-
|
|
|
$
|
358
|
|
|
|
|
Total Ameren
|
|
$
|
274
|
|
|
$
|
123
|
|
|
$
|
199
|
|
|
$
|
596
|
|
|
Ameren
|
|
Derivative assets - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Missouri
|
|
Fuel oils
|
|
$
|
20
|
|
|
$
|
-
|
|
|
$
|
3
|
|
|
$
|
23
|
|
|
|
|
Natural gas
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
1
|
|
|
|
29
|
|
|
|
30
|
|
|
|
|
Total derivative assets - commodity
contracts
|
|
$
|
22
|
|
|
$
|
1
|
|
|
$
|
32
|
|
|
$
|
55
|
|
|
|
|
Nuclear Decommissioning Trust
Fund
(c)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
3
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. large capitalization
|
|
|
234
|
|
|
|
-
|
|
|
|
-
|
|
|
|
234
|
|
|
|
|
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds
|
|
|
-
|
|
|
|
44
|
|
|
|
-
|
|
|
|
44
|
|
|
|
|
Municipal bonds
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
U.S. treasury and agency securities
|
|
|
-
|
|
|
|
65
|
|
|
|
-
|
|
|
|
65
|
|
|
|
|
Asset-backed securities
|
|
|
-
|
|
|
|
10
|
|
|
|
-
|
|
|
|
10
|
|
|
|
|
Other
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
Total Nuclear Decommissioning Trust Fund
|
|
$
|
237
|
|
|
$
|
121
|
|
|
$
|
-
|
|
|
$
|
358
|
|
|
|
|
Total Ameren Missouri
|
|
$
|
259
|
|
|
$
|
122
|
|
|
$
|
32
|
|
|
$
|
413
|
|
|
Ameren
|
|
Derivative assets - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Natural gas
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
-
|
|
|
|
77
|
|
|
|
77
|
|
|
|
|
Total Ameren Illinois
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
79
|
|
|
$
|
79
|
|
|
Genco
|
|
Derivative assets - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
$
|
10
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
11
|
|
|
|
|
Natural gas
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
Total Genco
|
|
$
|
12
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
13
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ameren
(a)
|
|
Derivative liabilities - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
|
|
Natural gas
|
|
|
22
|
|
|
|
-
|
|
|
|
176
|
|
|
|
198
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
2
|
|
|
|
78
|
|
|
|
80
|
|
|
|
|
Uranium
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
Total Ameren
|
|
$
|
24
|
|
|
$
|
2
|
|
|
$
|
255
|
|
|
$
|
281
|
|
|
Ameren
|
|
Derivative liabilities - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Missouri
|
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
|
|
Natural gas
|
|
|
12
|
|
|
|
-
|
|
|
|
14
|
|
|
|
26
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
1
|
|
|
|
8
|
|
|
|
9
|
|
|
|
|
Uranium
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
Total Ameren Missouri
|
|
$
|
13
|
|
|
$
|
1
|
|
|
$
|
23
|
|
|
$
|
37
|
|
|
Ameren
|
|
Derivative liabilities - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Natural gas
|
|
|
7
|
|
|
|
-
|
|
|
|
162
|
|
|
|
169
|
|
|
|
|
Power
|
|
|
-
|
|
|
|
-
|
|
|
|
217
|
|
|
|
217
|
|
|
|
|
Total Ameren Illinois
|
|
$
|
7
|
|
|
$
|
-
|
|
|
$
|
379
|
|
|
$
|
386
|
|
|
Genco
|
|
Derivative liabilities - commodity
contracts
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
|
|
Natural gas
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
Total Genco
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
3
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
|
(b)
|
The derivative asset and liability balances are presented net of counterparty credit considerations.
|
|
(c)
|
Balance excludes $(1) million of receivables, payables, and accrued income, net.
|
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative commodity contracts
|
|
|
Three Months
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
Other
(c)
|
|
|
Ameren
|
|
|
Fuel oils:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2012
|
|
$
|
3
|
|
|
$
|
(a
|
)
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
4
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
1
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
1
|
|
|
Total realized and unrealized gains (losses)
|
|
|
1
|
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
Purchases
|
|
|
2
|
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
1
|
|
|
Sales
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Transfers out of Level 3
|
|
|
-
|
|
|
|
(a
|
)
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
Ending balance at September 30, 2012
|
|
$
|
5
|
|
|
$
|
(a
|
)
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
6
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
2
|
|
|
$
|
(a
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
Power:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2012
|
|
$
|
26
|
|
|
$
|
(221
|
)
|
|
$
|
-
|
|
|
$
|
185
|
|
|
$
|
(10
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
(b)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4
|
|
|
|
4
|
|
|
Included in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(4
|
)
|
|
Included in regulatory assets/liabilities
|
|
|
(4
|
)
|
|
|
2
|
|
|
|
(a
|
)
|
|
|
(4
|
)
|
|
|
(6
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(4
|
)
|
|
|
2
|
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(6
|
)
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
3
|
|
|
Sales
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(5
|
)
|
|
Settlements
|
|
|
(4
|
)
|
|
|
54
|
|
|
|
-
|
|
|
|
(56
|
)
|
|
|
(6
|
)
|
|
Transfers out of Level 3
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(4
|
)
|
|
Ending balance at September 30, 2012
|
|
$
|
15
|
|
|
$
|
(165
|
)
|
|
$
|
-
|
|
|
$
|
122
|
|
|
$
|
(28
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
(5
|
)
|
|
$
|
(2
|
)
|
|
$
|
-
|
|
|
$
|
(10
|
)
|
|
$
|
(17
|
)
|
|
|
|
|
|
|
|
|
Uranium:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2012
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(1
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
Ending balance at September 30, 2012
|
|
$
|
(2
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(2
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(1
|
)
|
44
|
(b)
|
Net gains and losses on fuel oils and natural gas derivative commodity contracts are recorded in “Operating Expenses - Fuel”, while net gains and losses on
power derivative commodity contracts are recorded in “Operating Revenues - Electric”.
|
|
(c)
|
Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations, including the elimination of financial power contracts between Ameren
Illinois and Marketing Company.
|
The following table summarizes the changes in the fair value of financial
assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative commodity contracts
|
|
|
Three Months
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
Other
(c)
|
|
|
Ameren
|
|
|
Fuel oils:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2011
|
|
$
|
41
|
|
|
$
|
(a
|
)
|
|
$
|
21
|
|
|
$
|
6
|
|
|
$
|
68
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
(b)
|
|
|
-
|
|
|
|
(a
|
)
|
|
|
(5
|
)
|
|
|
(2
|
)
|
|
|
(7
|
)
|
|
Included in regulatory assets/liabilities
|
|
|
(12
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(12
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(12
|
)
|
|
|
(a
|
)
|
|
|
(5
|
)
|
|
|
(2
|
)
|
|
|
(19
|
)
|
|
Purchases
|
|
|
2
|
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
1
|
|
|
Sales
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Settlements
|
|
|
(10
|
)
|
|
|
(a
|
)
|
|
|
(7
|
)
|
|
|
(2
|
)
|
|
|
(19
|
)
|
|
Ending balance at September 30, 2011
|
|
$
|
20
|
|
|
$
|
(a
|
)
|
|
$
|
8
|
|
|
$
|
2
|
|
|
$
|
30
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
(14
|
)
|
|
$
|
(a
|
)
|
|
$
|
(6
|
)
|
|
$
|
(2
|
)
|
|
$
|
(22
|
)
|
|
|
|
|
|
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2011
|
|
$
|
(11
|
)
|
|
$
|
(106
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(117
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(2
|
)
|
|
|
(31
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(33
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(2
|
)
|
|
|
(31
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(33
|
)
|
|
Purchases
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Settlements
|
|
|
2
|
|
|
|
22
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
23
|
|
|
Ending balance at September 30, 2011
|
|
$
|
(11
|
)
|
|
$
|
(116
|
)
|
|
$
|
-
|
|
|
$
|
(1
|
)
|
|
$
|
(128
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
(2
|
)
|
|
$
|
(27
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(29
|
)
|
|
|
|
|
|
|
|
|
Power:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2011
|
|
$
|
25
|
|
|
$
|
(204
|
)
|
|
$
|
1
|
|
|
$
|
295
|
|
|
$
|
117
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(7
|
)
|
|
|
(7
|
)
|
|
Included in regulatory assets/liabilities
|
|
|
-
|
|
|
|
35
|
|
|
|
(a
|
)
|
|
|
(10
|
)
|
|
|
25
|
|
|
Total realized and unrealized gains (losses)
|
|
|
-
|
|
|
|
35
|
|
|
|
-
|
|
|
|
(17
|
)
|
|
|
18
|
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
2
|
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
Settlements
|
|
|
(7
|
)
|
|
|
35
|
|
|
|
(1
|
)
|
|
|
(45
|
)
|
|
|
(18
|
)
|
|
Transfers into Level 3
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
Transfers out of Level 3
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
Ending balance at September 30, 2011
|
|
$
|
18
|
|
|
$
|
(134
|
)
|
|
$
|
-
|
|
|
$
|
230
|
|
|
$
|
114
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
-
|
|
|
$
|
26
|
|
|
$
|
-
|
|
|
$
|
(4
|
)
|
|
$
|
22
|
|
|
Uranium:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at July 1, 2011
|
|
$
|
(2
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(2
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
-
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
Total realized and unrealized gains (losses)
|
|
|
-
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
Settlements
|
|
|
1
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
1
|
|
|
Ending balance at September 30, 2011
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(1
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
-
|
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
-
|
|
|
(b)
|
Net gains and losses on fuel oils and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power
derivative commodity contracts are recorded in Operating Revenues - Electric.
|
|
(c)
|
Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations, including the elimination of financial power contracts between Ameren
Illinois and Marketing Company.
|
45
The following table summarizes the changes in the fair value of financial assets and
liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative commodity contracts
|
|
|
Nine Months
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
Other
(c)
|
|
|
Ameren
|
|
|
Fuel oils:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2012
|
|
$
|
3
|
|
|
$
|
(a
|
)
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
4
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Purchases
|
|
|
4
|
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
4
|
|
|
Sales
|
|
|
(2
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
Settlements
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Transfers into Level 3
|
|
|
2
|
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
Ending balance at September 30, 2012
|
|
$
|
5
|
|
|
$
|
(a
|
)
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
6
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(1
|
)
|
|
|
|
|
|
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2012
|
|
$
|
(14
|
)
|
|
$
|
(160
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(174
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(2
|
)
|
|
|
(26
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(28
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(2
|
)
|
|
|
(26
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(28
|
)
|
|
Settlements
|
|
|
1
|
|
|
|
16
|
|
|
|
-
|
|
|
|
-
|
|
|
|
17
|
|
|
Transfer out of Level 3
|
|
|
15
|
|
|
|
170
|
|
|
|
-
|
|
|
|
-
|
|
|
|
185
|
|
|
Ending balance at September 30, 2012
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
7
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
Power:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2012
|
|
$
|
21
|
|
|
$
|
(140
|
)
|
|
$
|
-
|
|
|
$
|
234
|
|
|
$
|
115
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
(b)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11
|
|
|
|
11
|
|
|
Included in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
30
|
|
|
|
30
|
|
|
Included in regulatory assets/liabilities
|
|
|
5
|
|
|
|
(219
|
)
|
|
|
(a
|
)
|
|
|
40
|
|
|
|
(174
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
5
|
|
|
|
(219
|
)
|
|
|
-
|
|
|
|
81
|
|
|
|
(133
|
)
|
|
Purchases
|
|
|
22
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8
|
|
|
|
30
|
|
|
Sales
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
2
|
|
|
Settlements
|
|
|
(28
|
)
|
|
|
194
|
|
|
|
-
|
|
|
|
(206
|
)
|
|
|
(40
|
)
|
|
Transfers into Level 3
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
Transfers out of Level 3
|
|
|
(4
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
(3
|
)
|
|
Ending balance at September 30, 2012
|
|
$
|
15
|
|
|
$
|
(165
|
)
|
|
$
|
-
|
|
|
$
|
122
|
|
|
$
|
(28
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
(1
|
)
|
|
$
|
(187
|
)
(d)
|
|
$
|
-
|
|
|
$
|
44
|
|
|
$
|
(144
|
)
|
|
Uranium:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2012
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(1
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
Ending balance at September 30, 2012
|
|
$
|
(2
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(2
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2012
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(1
|
)
|
|
(b)
|
Net gains and losses on fuel oils and natural gas derivative commodity contracts are recorded in “Operating Expenses - Fuel”, while net gains and losses on
power derivative commodity contracts are recorded in “Operating Revenues - Electric”.
|
|
(c)
|
Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations, including the elimination of financial power contracts between Ameren
Illinois and Marketing Company.
|
|
(d)
|
The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois’ swap contracts, which expire in May 2032.
|
46
The following table summarizes the changes in the fair value of financial assets and
liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative commodity contracts
|
|
|
Nine Months
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
Other
(c)
|
|
|
Ameren
|
|
|
Fuel oils:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2011
|
|
$
|
30
|
|
|
$
|
(a
|
)
|
|
$
|
17
|
|
|
$
|
4
|
|
|
$
|
51
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
(b)
|
|
|
-
|
|
|
|
(a
|
)
|
|
|
7
|
|
|
|
3
|
|
|
|
10
|
|
|
Included in regulatory assets/liabilities
|
|
|
10
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
10
|
|
|
Total realized and unrealized gains (losses)
|
|
|
10
|
|
|
|
(a
|
)
|
|
|
7
|
|
|
|
3
|
|
|
|
20
|
|
|
Purchases
|
|
|
4
|
|
|
|
(a
|
)
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
3
|
|
|
Sales
|
|
|
(1
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Settlements
|
|
|
(23
|
)
|
|
|
(a
|
)
|
|
|
(15
|
)
|
|
|
(5
|
)
|
|
|
(43
|
)
|
|
Ending balance at September 30, 2011
|
|
$
|
20
|
|
|
$
|
(a
|
)
|
|
$
|
8
|
|
|
$
|
2
|
|
|
$
|
30
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
2
|
|
|
$
|
(a
|
)
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2011
|
|
$
|
(14
|
)
|
|
$
|
(134
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(148
|
)
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(3
|
)
|
|
|
(43
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(46
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(3
|
)
|
|
|
(43
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(46
|
)
|
|
Purchases
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
Settlements
|
|
|
6
|
|
|
|
60
|
|
|
|
-
|
|
|
|
-
|
|
|
|
66
|
|
|
Ending balance at September 30, 2011
|
|
$
|
(11
|
)
|
|
$
|
(116
|
)
|
|
$
|
-
|
|
|
$
|
(1
|
)
|
|
$
|
(128
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
(3
|
)
|
|
$
|
(31
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(34
|
)
|
|
|
|
|
|
|
|
|
Power:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2011
|
|
$
|
2
|
|
|
$
|
(352
|
)
|
|
$
|
3
|
|
|
$
|
383
|
|
|
$
|
36
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
(b)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(17
|
)
|
|
|
(18
|
)
|
|
Included in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
Included in regulatory assets/liabilities
|
|
|
6
|
|
|
|
82
|
|
|
|
(a
|
)
|
|
|
1
|
|
|
|
89
|
|
|
Total realized and unrealized gains (losses)
|
|
|
6
|
|
|
|
82
|
|
|
|
(1
|
)
|
|
|
(18
|
)
|
|
|
69
|
|
|
Purchases
|
|
|
29
|
|
|
|
-
|
|
|
|
-
|
|
|
|
32
|
|
|
|
61
|
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(17
|
)
|
|
|
(17
|
)
|
|
Settlements
|
|
|
(19
|
)
|
|
|
136
|
|
|
|
(2
|
)
|
|
|
(149
|
)
|
|
|
(34
|
)
|
|
Transfers into Level 3
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Transfers out of Level 3
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
Ending balance at September 30, 2011
|
|
$
|
18
|
|
|
$
|
(134
|
)
|
|
$
|
-
|
|
|
$
|
230
|
|
|
$
|
114
|
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
1
|
|
|
$
|
70
|
|
|
$
|
(1
|
)
|
|
$
|
7
|
|
|
$
|
77
|
|
|
|
|
|
|
|
|
|
Uranium:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1, 2011
|
|
$
|
2
|
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
2
|
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(4
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(4
|
)
|
|
Total realized and unrealized gains (losses)
|
|
|
(4
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(4
|
)
|
|
Settlements
|
|
|
1
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
1
|
|
|
Ending balance at September 30, 2011
|
|
$
|
(1
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(1
|
)
|
|
Change in unrealized gains (losses) related to assets/liabilities held at
September 30, 2011
|
|
$
|
(2
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
(2
|
)
|
|
(b)
|
Net gains and losses on fuel oils and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power
derivative commodity contracts are recorded in Operating Revenues - Electric.
|
|
(c)
|
Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations, including the elimination of financial power contracts between Ameren
Illinois and Marketing Company.
|
47
Transfers in 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. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate
the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter of 2012. Estimates of fair value based on exchange closing prices are deemed to be
a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on
electronic exchanges between the period ended September 30, 2012, and the previous reporting periods ended June 30, 2012 and December 31, 2011. 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. For the three and nine months ended September 30, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The
following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three and nine months ended September 30, 2012, and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Ameren - derivative commodity
contracts:
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
|
|
|
-
|
|
|
|
-
|
|
|
|
185
|
|
|
|
-
|
|
|
Transfers into Level 3 / Transfers out of Level 2 - Power
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
1
|
|
|
|
(1
|
)
|
|
Transfers out of Level 3 / Transfers into Level 2 - Power
|
|
|
(4
|
)
|
|
|
(2
|
)
|
|
|
(3
|
)
|
|
|
-
|
|
|
Net fair value of Level 3 transfers
|
|
$
|
(3
|
)
|
|
$
|
(4
|
)
|
|
$
|
185
|
|
|
$
|
(1
|
)
|
|
Ameren Missouri - derivative commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
|
|
|
-
|
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
Transfers into Level 3 / Transfers out of Level 2 - Power
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
Transfers out of Level 3 / Transfers into Level 2 - Power
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
1
|
|
|
Net fair value of Level 3 transfers
|
|
$
|
(2
|
)
|
|
$
|
-
|
|
|
$
|
13
|
|
|
$
|
-
|
|
|
Ameren Illinois - derivative commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
170
|
|
|
$
|
-
|
|
|
Genco - derivative commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
|
The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value
hierarchy. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. 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 and capital lease obligations and preferred stock at September 30, 2012, and December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2012
|
|
|
December 31, 2011
|
|
|
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
Ameren:
(a)(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations (including current portion)
|
|
$
|
6,987
|
|
|
$
|
8,024
|
|
|
$
|
6,856
|
|
|
$
|
7,800
|
|
|
Preferred stock
|
|
|
142
|
|
|
|
122
|
|
|
|
142
|
|
|
|
92
|
|
|
Ameren Missouri:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations (including current portion)
|
|
$
|
4,011
|
|
|
$
|
4,711
|
|
|
$
|
3,950
|
|
|
$
|
4,541
|
|
|
Preferred stock
|
|
|
80
|
|
|
|
73
|
|
|
|
80
|
|
|
|
55
|
|
|
Ameren Illinois:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (including current portion)
|
|
$
|
1,728
|
|
|
$
|
2,052
|
|
|
$
|
1,658
|
|
|
$
|
1,943
|
|
|
Preferred stock
|
|
|
62
|
|
|
|
49
|
|
|
|
62
|
|
|
|
37
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (including current portion)
|
|
$
|
824
|
|
|
$
|
790
|
|
|
$
|
824
|
|
|
$
|
839
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
|
(b)
|
Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests
on the balance sheet.
|
NOTE 8 - RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of
business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings.
Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our
material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K.
Put Option
Agreement and Guaranty
On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives
Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin energy centers. If Genco exercises the put option, the purchase price for all three energy centers will be the greater of $100 million or
the fair
48
market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase
price would be payable to Genco within one business day. Genco may exercise the put option at any time through March 28, 2014. The put option may be extended indefinitely for additional one-year periods by agreement of AERG and Genco. If Genco
exercises the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5
million. The put option premium paid by Genco was recorded as an “Other asset” on Genco’s consolidated balance sheet and is being amortized over two years. The amortization expense is eliminated in the consolidation of Ameren’s
financial statements.
The put option agreement requires AERG to secure and maintain an Ameren guaranty of payment of
contingent obligations under the agreement. Ameren and AERG entered into such a guaranty agreement on March 28, 2012. The guaranty shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option
agreement, or the put option agreement is terminated and no further payments are owed by AERG to Genco. As of September 30, 2012, Genco had not exercised the put option.
Intercompany Transfers
In 2012, Genco transferred various assets from its
Hutsonville and Meredosia energy centers to AERG. Both of the energy centers were retired in 2011. Genco received cash proceeds in the amount of $3 million. The transfer of the assets was accounted for as a transaction between entities
under common control; therefore, Genco did not recognize a gain on the transfer, and upon consolidation Ameren recorded the assets at carrying value.
Electric Power Supply Agreements
During the second quarter of 2012, Ameren
Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In
April 2012, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. In April 2012, Ameren Missouri
contracted to supply a portion of Ameren Illinois’ capacity requirements for $1 million and $3 million for the 12 months ending May 31, 2014 and 2015, respectively.
Collateral Postings
Under the terms of the Illinois power procurement
agreements entered into through a RFP process 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, meaning that
only the suppliers would be required to post collateral. Therefore, Ameren Missouri and Marketing Company, as winning suppliers in the RFP process, may be required to post collateral. As of December 31, 2011 and September 30, 2012, there
were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.
Marketing Company Sale of Trade Receivables to Ameren Illinois
In accordance with the Illinois Public Utilities Act, Ameren Illinois is required to purchase alternative retail electric suppliers’ receivables relating to Ameren Illinois’ delivery service
customers who elected to receive power supply from the alternative retail electric supplier. Beginning in June 2012, Marketing Company sold and Ameren Illinois purchased trade receivables relating to the power supply of residential customers using
Marketing Company as their alternative retail electric supplier. Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on
the assets associated with these purchase and sale transactions. As of September 30, 2012, Ameren Illinois’ payable to Marketing Company for the purchase of trade receivables totaled $6 million. For the nine months ended September 30,
2012 Ameren Illinois purchased $17 million of trade receivables from Marketing Company at a discount of less than $1 million. Marketing Company’s receivable from Ameren Illinois as well as Ameren Illinois’ payable to Marketing Company are
eliminated in the consolidated Ameren Corporation’s financial statements.
Money Pools
See Note 3 - Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.
49
The following table presents the impact on Ameren Missouri, Ameren Illinois and Genco of
related party transactions for the three and nine months ended September 30, 2012, and 2011. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and
the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
Nine Months
|
|
|
Agreement
|
|
Income Statement
Line Item
|
|
|
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Genco
|
|
|
Genco and EEI power supply
|
|
Operating Revenues
|
|
|
2012
|
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
217
|
|
|
|
|
$
|
(a
|
)
|
|
$
|
(a
|
)
|
|
$
|
603
|
|
|
agreements with Marketing Company
|
|
|
|
|
2011
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
289
|
|
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
771
|
|
|
Ameren Missouri power supply
|
|
Operating Revenues
|
|
|
2012
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
agreements with Ameren Illinois
|
|
|
|
|
2011
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
|
|
1
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
Ameren Missouri and Ameren Illinois
|
|
Operating Revenues
|
|
|
2012
|
|
|
|
5
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
|
|
14
|
|
|
|
1
|
|
|
|
(a
|
)
|
|
rent and facility services
|
|
|
|
|
2011
|
|
|
|
4
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
|
|
12
|
|
|
|
1
|
|
|
|
(a
|
)
|
|
Ameren Missouri and Genco gas
|
|
Operating Revenues
|
|
|
2012
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
transportation agreement
|
|
|
|
|
2011
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
Transmission services agreement
|
|
Operating Revenues
|
|
|
2012
|
|
|
|
(a
|
)
|
|
|
5
|
|
|
|
(a
|
)
|
|
|
|
|
(a
|
)
|
|
|
11
|
|
|
|
(a
|
)
|
|
with Marketing Company
|
|
|
|
|
2011
|
|
|
|
(a
|
)
|
|
|
3
|
|
|
|
(a
|
)
|
|
|
|
|
(a
|
)
|
|
|
8
|
|
|
|
(a
|
)
|
|
Total Operating Revenues
|
|
|
|
|
2012
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
217
|
|
|
|
|
$
|
14
|
|
|
$
|
12
|
|
|
$
|
603
|
|
|
|
|
|
|
|
2011
|
|
|
|
4
|
|
|
|
3
|
|
|
|
289
|
|
|
|
|
|
13
|
|
|
|
9
|
|
|
|
771
|
|
|
Ameren Illinois power supply
|
|
Purchased Power
|
|
|
2012
|
|
|
$
|
(a
|
)
|
|
$
|
83
|
|
|
$
|
(a
|
)
|
|
|
|
$
|
(a
|
)
|
|
$
|
243
|
|
|
$
|
(a
|
)
|
|
agreements with Marketing Company
|
|
|
|
|
2011
|
|
|
|
(a
|
)
|
|
|
66
|
|
|
|
(a
|
)
|
|
|
|
|
(a
|
)
|
|
|
160
|
|
|
|
(a
|
)
|
|
Ameren Illinois power supply
|
|
Purchased Power
|
|
|
2012
|
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
agreements with Ameren Missouri
|
|
|
|
|
2011
|
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
|
|
(a
|
)
|
|
|
1
|
|
|
|
(a
|
)
|
|
EEI power supply agreement with
|
|
Purchased Power
|
|
|
2012
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
(b
|
)
|
|
Marketing Company
|
|
|
|
|
2011
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
24
|
|
|
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
36
|
|
|
Total Purchased Power
|
|
|
|
|
2012
|
|
|
$
|
(a
|
)
|
|
$
|
83
|
|
|
$
|
(b
|
)
|
|
|
|
$
|
(a
|
)
|
|
$
|
243
|
|
|
$
|
(b
|
)
|
|
|
|
|
|
|
2011
|
|
|
|
(a
|
)
|
|
|
66
|
|
|
|
24
|
|
|
|
|
|
(a
|
)
|
|
|
161
|
|
|
|
36
|
|
|
Ameren Services support services
|
|
Other Operations
|
|
|
2012
|
|
|
$
|
26
|
|
|
$
|
22
|
|
|
$
|
7
|
|
|
|
|
$
|
81
|
|
|
$
|
67
|
|
|
$
|
17
|
|
|
agreement
|
|
and Maintenance
|
|
|
2011
|
|
|
|
27
|
|
|
|
20
|
|
|
|
4
|
|
|
|
|
|
86
|
|
|
|
65
|
|
|
|
14
|
|
|
Insurance premiums
(c)
|
|
Other Operations
|
|
|
2012
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
|
and Maintenance
|
|
|
2011
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
|
|
|
(b
|
)
|
|
|
(a
|
)
|
|
|
-
|
|
|
Total Other Operations and
|
|
|
|
|
2012
|
|
|
$
|
26
|
|
|
$
|
22
|
|
|
$
|
7
|
|
|
|
|
$
|
81
|
|
|
$
|
67
|
|
|
$
|
17
|
|
|
Maintenance Expenses
|
|
|
|
|
2011
|
|
|
|
27
|
|
|
|
20
|
|
|
|
4
|
|
|
|
|
|
86
|
|
|
|
65
|
|
|
|
14
|
|
|
Money pool borrowings (advances)
|
|
Interest Charges
|
|
|
2012
|
|
|
$
|
-
|
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
|
|
$
|
-
|
|
|
$
|
(b
|
)
|
|
$
|
(b
|
)
|
|
|
|
|
|
|
2011
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(b
|
)
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(b
|
)
|
|
(b)
|
Amount less than $1 million.
|
|
(c)
|
Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
|
NOTE 9 - COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, 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 the notes
to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part
II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Energy Center in this report.
50
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at September 30, 2012. 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
for Single Incidents
|
|
|
Public liability and nuclear worker liability:
|
|
|
|
|
|
|
|
|
|
American Nuclear Insurers
|
|
$
|
375
|
|
|
$
|
-
|
|
|
Pool participation
|
|
|
12,219
|
(a)
|
|
|
118
|
(b)
|
|
|
|
$
|
12,594
|
(c)
|
|
$
|
118
|
|
|
Property damage:
|
|
|
|
|
|
|
|
|
|
Nuclear Electric Insurance Ltd.
|
|
$
|
2,750
|
(d)
|
|
$
|
23
|
|
|
Replacement power:
|
|
|
|
|
|
|
|
|
|
Nuclear Electric Insurance Ltd
|
|
$
|
490
|
(e)
|
|
$
|
9
|
|
|
Energy Risk Assurance Company
|
|
$
|
64
|
(f)
|
|
$
|
-
|
|
|
(a)
|
Provided through mandatory participation in an industry wide retrospective premium assessment program.
|
|
(b)
|
Retrospective premium under Price-Anderson. 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 $17.5 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 $118
million per incident for each licensed reactor it operates with a maximum of $17.5 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)
|
Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in
excess of the $500 million primary coverage.
|
|
(e)
|
Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52
weeks, which commences after the first eight 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.
|
|
(f)
|
Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52
weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company is an affiliate and has reinsured
this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.
|
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. 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 five-year inflationary adjustment as prescribed by the most
recent Price-Anderson Act renewal was effective October 29, 2008. 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
Price-Anderson.
Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.’s policies,
subject to an industry wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
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, or liquidity.
Other Obligations
To supply a portion of the fuel requirements of our
energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution.
The table below presents our estimated fuel, purchased power, and other commitments at September 30, 2012. Ameren’s and Ameren Missouri’s purchased power obligations include a 102-MW power purchase agreement with a wind farm operator
that expires in 2024. Ameren’s and Ameren Illinois’ purchased power obligations 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, meter reading services, and an Ameren tax credit obligation at September 30, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
|
Natural Gas
|
|
|
Nuclear
|
|
|
Purchased
Power
(a)
|
|
|
Methane
Gas
|
|
|
Other
|
|
|
Total
|
|
|
Ameren:
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
727
|
|
|
$
|
82
|
|
|
$
|
22
|
|
|
$
|
24
|
|
|
$
|
1
|
|
|
$
|
110
|
|
|
$
|
966
|
|
|
2013
|
|
|
871
|
|
|
|
372
|
|
|
|
35
|
|
|
|
420
|
|
|
|
3
|
|
|
|
92
|
|
|
|
1,793
|
|
|
2014
|
|
|
774
|
|
|
|
243
|
|
|
|
93
|
|
|
|
308
|
|
|
|
3
|
|
|
|
100
|
|
|
|
1,521
|
|
|
2015
|
|
|
702
|
|
|
|
134
|
|
|
|
86
|
|
|
|
164
|
|
|
|
4
|
|
|
|
61
|
|
|
|
1,151
|
|
|
2016
|
|
|
685
|
|
|
|
55
|
|
|
|
104
|
|
|
|
78
|
|
|
|
4
|
|
|
|
52
|
|
|
|
978
|
|
|
Thereafter
|
|
|
978
|
|
|
|
130
|
|
|
|
346
|
|
|
|
749
|
|
|
|
104
|
|
|
|
246
|
|
|
|
2,553
|
|
|
Total
|
|
$
|
4,737
|
|
|
$
|
1,016
|
|
|
$
|
686
|
|
|
$
|
1,743
|
|
|
$
|
119
|
|
|
$
|
661
|
|
|
$
|
8,962
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
|
Natural Gas
|
|
|
Nuclear
|
|
|
Purchased
Power
(a)
|
|
|
Methane
Gas
|
|
|
Other
|
|
|
Total
|
|
|
Ameren Missouri:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
614
|
|
|
$
|
16
|
|
|
$
|
22
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
47
|
|
|
$
|
703
|
|
|
2013
|
|
|
609
|
|
|
|
57
|
|
|
|
35
|
|
|
|
19
|
|
|
|
3
|
|
|
|
54
|
|
|
|
777
|
|
|
2014
|
|
|
625
|
|
|
|
43
|
|
|
|
93
|
|
|
|
19
|
|
|
|
3
|
|
|
|
68
|
|
|
|
851
|
|
|
2015
|
|
|
614
|
|
|
|
24
|
|
|
|
86
|
|
|
|
19
|
|
|
|
4
|
|
|
|
37
|
|
|
|
784
|
|
|
2016
|
|
|
644
|
|
|
|
10
|
|
|
|
104
|
|
|
|
19
|
|
|
|
4
|
|
|
|
28
|
|
|
|
809
|
|
|
Thereafter
|
|
|
921
|
|
|
|
36
|
|
|
|
346
|
|
|
|
155
|
|
|
|
104
|
|
|
|
144
|
|
|
|
1,706
|
|
|
Total
|
|
$
|
4,027
|
|
|
$
|
186
|
|
|
$
|
686
|
|
|
$
|
234
|
|
|
$
|
119
|
|
|
$
|
378
|
|
|
$
|
5,630
|
|
|
Ameren Illinois:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
-
|
|
|
$
|
66
|
|
|
$
|
-
|
|
|
$
|
21
|
|
|
$
|
-
|
|
|
$
|
8
|
|
|
$
|
95
|
|
|
2013
|
|
|
-
|
|
|
|
287
|
|
|
|
-
|
|
|
|
401
|
|
|
|
-
|
|
|
|
22
|
|
|
|
710
|
|
|
2014
|
|
|
-
|
|
|
|
197
|
|
|
|
-
|
|
|
|
289
|
|
|
|
-
|
|
|
|
22
|
|
|
|
508
|
|
|
2015
|
|
|
-
|
|
|
|
108
|
|
|
|
-
|
|
|
|
145
|
|
|
|
-
|
|
|
|
24
|
|
|
|
277
|
|
|
2016
|
|
|
-
|
|
|
|
45
|
|
|
|
-
|
|
|
|
59
|
|
|
|
-
|
|
|
|
24
|
|
|
|
128
|
|
|
Thereafter
|
|
|
-
|
|
|
|
94
|
|
|
|
-
|
|
|
|
594
|
|
|
|
-
|
|
|
|
102
|
|
|
|
790
|
|
|
Total
|
|
$
|
-
|
|
|
$
|
797
|
|
|
$
|
-
|
|
|
$
|
1,509
|
|
|
$
|
-
|
|
|
$
|
202
|
|
|
$
|
2,508
|
|
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
86
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
31
|
|
|
$
|
117
|
|
|
2013
|
|
|
177
|
|
|
|
28
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
|
|
215
|
|
|
2014
|
|
|
100
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
|
|
110
|
|
|
2015
|
|
|
57
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
59
|
|
|
2016
|
|
|
10
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
|
Thereafter
|
|
|
11
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11
|
|
|
Total
|
|
$
|
441
|
|
|
$
|
33
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
48
|
|
|
$
|
522
|
|
|
(a)
|
The purchased power amounts for Ameren and Ameren Illinois include a 20-year agreement for renewable energy credits that was entered into in December 2010 with various
renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.
|
|
(b)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
Previously, Ameren Illinois entered into an agreement to purchase approximately 15.5 billion cubic feet of synthetic natural gas annually
over a 10-year period beginning in 2016 for its natural gas customers. The agreement was entered into pursuant to an Illinois law, which became effective August 2, 2011. Ameren Illinois’ obligations under the agreement were contingent on
the counterparty reaching certain milestones during the project development and the construction of the plant that was to produce the synthetic natural gas. The counterparty failed to meet certain milestones during the second quarter of 2012 and,
accordingly, the contract was terminated.
Environmental Matters
We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases
of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse
environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological
and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or
hazardous materials (including wastes) requires release prevention plans and emergency response procedures.
In addition to existing laws and regulations, including the Illinois MPS that applies to Genco’s and AERG’s
energy centers in Illinois, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including
Ameren, Ameren Missouri and Genco, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards
for SO
2
and NO
2
emissions; the CSAPR, which would have required further reductions of
SO
2
and NO
x
emissions from power plants; a regulation governing management of CCR
and coal ash impoundments; the MATS, which requires reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO
2
, and NO
x
emissions from new sources; and new regulations under the Clean Water Act that could require significant capital
expenditures such as new water intake structures or cooling towers at our energy centers. The EPA has proposed
CO
2
limits for new coal-fired and natural gas-fired combined
cycle units and is expected to propose limits for existing units in the future. These new and
52
proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR
being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental
regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years for Ameren, Ameren Missouri and Genco. Actions required to ensure that our facilities and operations are in compliance with
environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of
operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.
The estimates in the table below contain all of the known capital costs to comply with existing environmental
regulations, including the CAIR, and our assessment of the potential impacts of the EPA’s proposed regulation for CCR, the finalized MATS, and the revised national ambient air quality standards for SO
2
and NO
x
emissions as of September 30, 2012. The estimates for Ameren, Genco and AERG in the table below have decreased from
the estimates in the Form 10-K primarily due to the vacated CSAPR and the impacts of the MPS variance granted to AER by the Illinois Pollution Control Board, both of which are discussed below. Additionally, as discussed below, AERG canceled plans
for major precipitator upgrades at its E.D. Edwards energy center. The vacated CSAPR did not significantly impact Ameren Missouri’s estimated capital expenditures. The estimates in the table below assume that CCR will continue to be regarded as
nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The
estimates shown in the table below could change significantly depending upon a variety of factors including:
|
•
|
|
additional or modified federal or state requirements;
|
|
•
|
|
further regulation of greenhouse gas emissions;
|
|
•
|
|
revisions to CAIR or reinstatement of CSAPR;
|
|
•
|
|
new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO
2
, and NO
x
emissions;
|
|
•
|
|
additional rules governing air pollutant transport;
|
|
•
|
|
finalized regulations under the Clean Water Act;
|
|
•
|
|
finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;
|
|
•
|
|
variations in costs of material or labor; and
|
|
•
|
|
alternative compliance strategies or investment decisions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
2013 - 2016
|
|
|
2017 - 2021
|
|
|
Total
|
|
|
AMO
(a)
|
|
$
|
55
|
|
|
$
|
325
|
|
|
|
-
|
|
|
$
|
400
|
|
|
$
|
845
|
|
|
|
-
|
|
|
$
|
1,030
|
|
|
$
|
1,225
|
|
|
|
-
|
|
|
$
|
1,485
|
|
|
Genco
|
|
|
130
|
|
|
|
90
|
|
|
|
-
|
|
|
|
110
|
|
|
|
225
|
|
|
|
-
|
|
|
|
250
|
|
|
|
445
|
|
|
|
-
|
|
|
|
490
|
|
|
AERG
|
|
|
5
|
|
|
|
15
|
|
|
|
-
|
|
|
|
25
|
|
|
|
15
|
|
|
|
-
|
|
|
|
25
|
|
|
|
35
|
|
|
|
-
|
|
|
|
55
|
|
|
Ameren
|
|
$
|
190
|
|
|
$
|
430
|
|
|
|
-
|
|
|
$
|
535
|
|
|
$
|
1,085
|
|
|
|
-
|
|
|
$
|
1,305
|
|
|
$
|
1,705
|
|
|
|
-
|
|
|
$
|
2,030
|
|
|
(a)
|
Ameren Missouri’s expenditures are expected to be recoverable from ratepayers.
|
The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future
market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in the current year and in future years sharply declined below 2011 levels primarily because of
declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at
its Newton energy center. These scrubbers were originally expected to be installed in late 2013 and early 2014. The ultimate installation of these scrubbers, now estimated to occur by the end of 2019, has been postponed until such time as the
incremental investment necessary for completion is justified by visible market conditions. However, Genco will continue to incur capital costs related to the construction of these scrubbers. The table above includes Genco’s estimated costs of
approximately $130 million in 2012 and approximately $20 million annually, excluding capitalized interest, from 2013 through 2016 for the construction of the two scrubbers. In addition to Genco’s reduction in estimated capital expenditures,
AERG canceled plans for major precipitator upgrades at its E.D. Edwards energy center. AERG is pursuing advanced technology and enhanced operating techniques that have the potential to achieve similar pollution control effects as the precipitator
upgrades. Based on the MPS variance granted by the Illinois Pollution Control Board in September 2012, AER is currently scheduled to complete the Newton scrubbers by the end of 2019. See additional information below regarding the MPS variance
granted by the Illinois Pollution Control Board.
The following sections describe the more significant environmental rules
that affect or could affect our operations.
Clean Air Act
Both federal and state laws require significant reductions in SO
2
and NO
x
emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO
2
and NO
x
emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the
District of Columbia, to participate in cap-and-trade programs to reduce annual SO
2
emissions, annual NO
x
emissions, and ozone season NO
x
emissions.
53
In December 2008, the United States Court of Appeals for the District of
Columbia remanded the CAIR to the EPA for further action to remedy the rule’s flaws, but allowed the CAIR’s cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR
replacement. The CSAPR was to become effective on January 1, 2012, for SO
2
and annual NO
x
reductions and on May 1, 2012, for ozone season NO
x
reductions, with further reductions in 2014. Multiple legal challenges were filed requesting to have CSAPR partially or entirely vacated. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the
CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR’s emission limits on states. In
October 2012, the EPA filed an appeal of that decision to the full District of Columbia Court of Appeals. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned.
In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other
hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards
require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place. The MATS do
not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be averaged for the entire power plant. Compliance is required by April 2015
or, with a case-by-case extension, by April 2016. Ameren Missouri’s Labadie and Meramec energy centers requested and were granted an extension to comply with the MATS by April 2016.
Separately, on June 14, 2012, the EPA proposed to make more stringent the national ambient air quality standard for fine particulate
matter. Under the proposed standard, the EPA and states would develop control measures designed to reduce the emission of fine particulate matter below required levels. Such measures may or may not apply to power plants. The EPA expects to issue a
final standard for fine particulate matter by the end of 2012, and require each state to comply with the final standard by 2020, or 2025 if granted an extension of time to achieve compliance. In September 2011, the EPA announced that it was
implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard for ozone again in 2013. The state of Illinois and the state of Missouri will be required to develop attainment plans to comply with
the 2008 ambient air quality standards for ozone and are expected to be required to develop attainment plans for fine particulate matter if the new standard is adopted. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new
standards.
Ameren Missouri’s current environmental compliance plan for air emissions from its energy
centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren
Missouri’s energy centers have historically burned, which allowed Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux
energy center to reduce SO
2
emissions. Currently, Ameren
Missouri’s compliance plan assumes the installation of two scrubbers within its coal-fired fleet, mercury control technology, and precipitator upgrades at multiple energy centers during the next 10 years. However, Ameren Missouri is currently
evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations.
On September 20, 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO
2
emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The
Illinois Pollution Control Board approved AER’s proposed plan to restrict its SO
2
emissions through 2014 to levels lower than those required by the existing MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board’s order also included the
following provisions:
|
•
|
|
A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco’s Newton energy
center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.
|
|
•
|
|
A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction
does not impact Genco’s ability to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide
capture and storage.
|
AER accepted the terms and conditions of the variance set forth in the order.
Under the MPS, as amended by the recent variance, AER is required to reduce mercury and NO
x
emissions by 2015 and SO
2
emissions by the end of 2019. The Illinois Pollution Control
Board’s September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber
54
installations and other pollution controls at some of AER’s energy centers. To comply with the MPS and other air emissions laws and regulations, Genco and AERG are installing equipment
designed to reduce their emissions of mercury, NO
x
, and
SO
2
. Genco and AERG have installed a total of three scrubbers
at two energy centers. Two additional scrubbers are being constructed at Genco’s Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel
costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.
The completion of Ameren’s, Ameren Missouri’s and Genco’s review of recently finalized environmental regulations and
compliance measures could result in significant increases in capital expenditures and operating costs. Environmental compliance costs could be prohibitive at some of Ameren’s, Ameren Missouri’s and Genco’s energy centers as the
expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.
Emission Allowances
The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO
x
budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the
installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program’s allowances for SO
2
emissions and created annual and ozone season NO
x
allowances. Ameren, Ameren Missouri and Genco expect to have adequate
CAIR allowances for 2012 to avoid needing to make external purchases to comply with these programs.
Global Climate Change
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse
gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO
2
emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to
which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse
gases vary among our energy centers, but coal-fired power plants are significant sources of CO
2
. The enactment of a climate change law could result in a significant rise in household costs, and rates for electricity could rise significantly. The burden could fall particularly hard on electricity
consumers and upon the economy in the Midwest because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO
2
as coal when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired
power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our
utility customers and many industrial processes that use natural gas.
In December 2009, the EPA issued
its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including
CO
2
, endanger human health and welfare and that emissions of
greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act
effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.
Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized the “Tailoring Rule,” which established new higher emission thresholds
beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon
renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in
emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New
major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material
impact on our energy centers depends upon how state agencies apply the EPA’s guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in
operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia upheld the Tailoring Rule.
Separately, on March 27, 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired
electric energy centers and
55
therefore does not impact any of Ameren’s, Ameren Missouri’s, or Genco’s existing energy centers. Ameren anticipates this proposed rule, if enacted, could make the construction of
new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2012. Any federal climate change legislation that is enacted may preempt the EPA’s regulation of greenhouse gas emissions, including the
Tailoring Rule and the Carbon Pollution Standard for New Power Plants, particularly as it relates to power plant greenhouse gas emissions.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which,
in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs
to comply with future legislation or regulations might force Ameren, Ameren Missouri and Genco as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible
impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s, Ameren Missouri’s, and Genco’s results of operations, financial position, and liquidity.
Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to
address damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged CO
2
emissions from several industrial companies, including Ameren Missouri
and Genco, created the atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. The case has been appealed to the appellate court.
The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and
state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our
coal-fired energy centers and our customers’ costs is unknown, but could result in significant increases in our capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected
return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.
NSR and Clean Air Litigation
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 plants
implemented modifications. The EPA’s inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.
Commencing in 2005, Genco received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act.
The requests sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG’s E.D. Edwards and Duck Creek energy centers. In August 2012, Genco
received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco’s Newton energy center violated federal
law. Genco believes its defenses to the allegations described in the Notice of Violation are meritorious. Ameren and Genco are unable to predict the outcome of this matter and whether EPA will address this Notice of Violation administratively or
through litigation.
Following the issuance of a Notice of Violation, 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 alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri
violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri’s motion to dismiss various aspects of the EPA’s penalty claims. The EPA’s claims for
injunctive relief, including to require the installation of pollution control equipment, remain. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well
as the Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.
Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, Ameren Missouri and Genco. A resolution could
result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be
incurred.
56
Clean Water Act
In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per
day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant’s intake
screens or to reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling
system. The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at Ameren, Ameren Missouri and Genco with cooling water systems
are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and Genco are currently evaluating
the proposed rule, and their assessment of the proposed rule’s impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have an adverse effect
on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.
In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for
wastewater discharges to surface water that are based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue
a proposed rule in December 2012 and to finalize the rule in May 2014. We are unable at this time to predict the impact of this development.
Remediation
We are
involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties 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 the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve
facilities that were transferred by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs
associated with pre-existing environmental contamination at the transferred sites.
As of September 30, 2012, Ameren and
Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. These are in various stages of investigation, evaluation, and remediation. Based on current estimated plans, Ameren and Ameren Illinois could substantially
conclude remediation efforts at most of these sites by 2015. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental
adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.
As of September 30, 2012, Ameren and Ameren Missouri own or are otherwise responsible for 10 former MGP sites in Missouri and one site in Iowa. Ameren Missouri does not currently have a rate rider
mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. Ameren Missouri does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs.
The following table presents, as of September 30, 2012, the estimated probable obligation to remediate these former MGP
sites.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimate
|
|
|
Recorded
Liability
(a)
|
|
|
|
|
Low
|
|
|
High
|
|
|
|
Ameren
|
|
$
|
133
|
|
|
$
|
207
|
|
|
$
|
133
|
|
|
Ameren Missouri
|
|
|
3
|
|
|
|
4
|
|
|
|
3
|
|
|
Ameren Illinois
|
|
|
130
|
|
|
|
203
|
|
|
|
130
|
|
|
(a)
|
Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was a better estimate.
|
Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of September 30, 2012, Ameren
Illinois estimated that obligation 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 a landfill, underground storage tanks, and a water treatment plant in Illinois. As of September 30, 2012, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the
obligation for these sites.
57
Ameren Missouri has responsibility for the investigation and potential cleanup of two waste
sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery
operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri,
along with two other PRPs, is currently performing a site investigation. As of September 30, 2012, 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’s other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an
electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in
2005. Ameren Missouri anticipates this trust fund will be sufficient to complete the remaining adjacent off-site cleanup and therefore has no recorded liability at September 30, 2012, related to this site.
Ameren Missouri also has a federal agency mandate to complete a site investigation for a site in Illinois. In 2000, the EPA notified
Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, 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 that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri has joined with other PRPs to
evaluate the extent of potential contamination with respect to Sauget Area 2.
The Sauget Area 2 investigations overseen by
the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2012. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last
several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2. As of
September 30, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri recorded a liability of $0.3 million to represent its estimated minimum obligation, as no other amount within the range was a better
estimate.
Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate
circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine whether such practices will result in future environmental commitments or affect our results of operations, financial position, or
liquidity.
Ash Management
There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory
framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but
either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants
either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to
closure and postclosure care under the proposed regulations. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other
industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and Genco are currently evaluating all of the proposed regulations to determine whether current management of CCR, including
beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and Genco also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be
material, if such regulations are adopted.
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. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.
Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of September 30, 2012, Ameren Missouri had an insurance receivable balance
subject to liability coverage of $68 million.
In June 2010, Ameren Missouri sued an insurance company that was providing
Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to
indemnify Ameren
58
Missouri for the losses experienced from the incident. In January 2011, the court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage
agreement. Ameren Missouri filed an appeal of the January 2011 ruling with the United States Court of Appeals for the Eighth Circuit, seeking the ability to pursue resolution of this dispute outside of a dispute resolution process under the terms of
its coverage agreement. In August 2012, the court of appeals remanded the case to the district court for consideration of whether Missouri law voids the alternative dispute resolution provision of the insurance policy. Separately, in April 2012,
Ameren Missouri sued a different insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, which is pending in the United States District Court for the Eastern
District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident. The district court has denied the insurer’s motion for dismissal, and the insurer
has filed a notice of appeal in the United States Court of Appeals for the Eight Circuit.
Until Ameren’s remaining
liability insurance claims and the related litigation are resolved, we are unable to determine the total impact the breach could have on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity beyond those
amounts already recognized.
Asbestos-related Litigation
Ameren, Ameren Missouri, Ameren Illinois and EEI have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure.
Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 272 parties named in some pending cases and as few as two in others. In the cases pending as of
September 30, 2012, the average number of parties was 80.
The claims filed against Ameren, Ameren Missouri and Ameren
Illinois allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Certain former Ameren Illinois energy centers are now owned by either Genco or AERG. As a part of the transfer
of energy center ownership in 2000 and 2003, Ameren Illinois contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to each transfer. 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 the Ameren Companies as of September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
Ameren
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Genco
|
|
Total
(a)
|
|
4
|
|
74
|
|
93
|
|
(b)
|
|
120
|
|
(a)
|
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
|
|
(b)
|
As of September 30, 2012, six asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect
to liabilities arising from asbestos-related claims.
|
At September 30, 2012, Ameren, Ameren Missouri,
Ameren Illinois and Genco had liabilities of $23 million, $9 million, $14 million, and $- million, respectively, recorded to represent their estimate of their obligations related to asbestos claims.
Ameren Illinois has a tariff rider which permits recovery from customers within IP’s historical service territory of
asbestos-related litigation claims that occurred within IP’s historical service territory. The rider can recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount
included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At September 30, 2012, the trust fund balance was $23 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.
Illinois Sales and Use Tax Exemptions and Credits
In
Exelon Corporation v. Department of Revenue
, the Illinois Supreme Court decided in 2009 that electricity is tangible personal
property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, Genco, including EEI, and
AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible
personal property applies to sales and use tax manufacturing exemptions and credits. On November 2, 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois’ position that EEI did not qualify for the
manufacturing exemption it used during 2010. EEI is challenging the state of Illinois’ position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren and Genco do not
believe that it is probable that the state of Illinois will prevail and therefore have not recorded a
59
charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $27 million and $19
million, respectively, which represents the maximum potential tax liability to Ameren and Genco, excluding any penalties assessed or interest accrued.
Genco, including EEI, and AERG do not anticipate claiming any additional manufacturing exemptions or credits in 2012, pending discussions with the Illinois Department of Revenue, and therefore will pay
sales or use tax on the applicable purchases. Each company, however, is reserving the right to apply for applicable refunds at a later date.
NOTE 10 - CALLAWAY ENERGY CENTER
Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other
commercial nuclear power plants. Under the NWPA, Ameren and other utilities who own and operate those plants are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of
the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatt hour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste fee 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 and other utilities have entered into standard contracts with the federal government. The government, represented
by the DOE, is responsible for implementing these provisions of the NWPA. Consistent with the NWPA and its contract, Ameren Missouri collects one mill from its electric customers for each kilowatt hour of electricity that it generates and sells from
its Callaway energy center.
Although both the NWPA and the standard contract stated that the federal government would begin
to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren
Missouri has sufficient installed capacity at its Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of
the energy center’s current licensed life.
Until January 2009, the DOE program provided for spent nuclear fuel disposal
to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. In January 2009, the Obama administration announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while
acknowledging the federal government’s continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of
spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements
for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund. Most of these recommendations require action by the DOE and the United States Congress.
In view of the federal government’s efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of
individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit seeking the suspension of the one mill nuclear waste fee, alleging that
the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that DOE’s fee adequacy review was legally inadequate and remanded the
matter to the DOE. While the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that
should be collected. The DOE’s delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operation of the energy center.
As a result of DOE’s failure to begin to dispose of the utilities’ spent nuclear fuel and fulfill its contractual obligations,
Ameren Missouri and other nuclear power plant owners have also sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs which it would not have incurred had DOE
performed its contractual obligations. These costs included the reracking of the Callaway energy center’s spent fuel pool, certain NRC fees, and Missouri ad valorem taxes. In June 2011, the parties reached a settlement that included a payment
to Ameren Missouri for spent fuel storage and related costs through 2010 and, thereafter, annual payment of such costs after they are incurred through 2013 or any other mutually agreed extension. In March 2012, Ameren Missouri submitted its 2011
costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2011 cost reimbursement of $1 million during the fourth quarter of 2012.
In December 2011, Ameren Missouri filed a license extension application with the NRC to extend its Callaway energy center’s
operating license from 2024 to 2044. There is no date by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in
60
approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC’s confidence that permanent disposal of spent nuclear fuel will be
available when needed. In a June 2012 decision, the United States Court of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC’s obligations under the National Environmental
Policy Act required a more thorough environmental analysis in support of the NRC’s waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings,
including the Callaway license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the Court’s
remand. In September 2012, the NRC directed its staff to issue, within two years, a generic environmental impact statement and a final rule to address the Court’s ruling. The NRC also stated that a site-specific analysis of these
issues could be conducted in rare circumstances. If the Callaway energy center’s license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy
center and intends to begin transferring spent fuel assemblies to this facility by 2020.
Electric utility rates charged to
customers provide for the recovery of the Callaway energy center’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the nuclear center, ending with the expiration of
the energy center’s current operating license in 2024. It is assumed that the Callaway energy center site will be 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. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren
Missouri’s customers. These costs amounted to $7 million in each of the years 2011, 2010, and 2009. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study for decommissioning its Callaway energy center. Electric
rates may be adjusted at such times to reflect changed estimates. The last cost study was filed with the MoPSC in September 2011. After considering the results of that cost study and associated financial analysis, Ameren Missouri recommended to the
MoPSC that the current rate of deposits to the trust fund continues to be appropriate and does not need to be changed. In the current electric rate case, Ameren Missouri and the MoPSC staff filed a stipulation and agreement which supported keeping
the customer contribution level at the current level and recommended approval of the return rates used in Ameren Missouri’s cost study. A decision from the MoPSC is still pending. If Ameren Missouri’s operating license extension
application is approved by the NRC, a revised financial analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension. Amounts collected from customers are deposited in an
external trust fund to provide for the Callaway energy center’s decommissioning. 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. The fair value of
the nuclear decommissioning trust fund for Ameren Missouri’s Callaway energy center is reported as “Nuclear decommissioning trust fund” in Ameren’s and Ameren Missouri’s balance sheet. 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.
See Note 2 - Rate and Regulatory Matters for additional information related to the Callaway energy center.
NOTE 11 - ASSET IMPAIRMENTS
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances
indicate that the carrying value, or book value, of such assets may not be recoverable. Under applicable accounting guidance, whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the
assets with the carrying value of the assets. If the carrying value exceeds the estimated undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value.
Power prices in the Midwest affect the amount of revenues and cash flows Merchant Generation and Genco can realize by marketing power
into the wholesale and retail markets. During the first quarter of 2012, the observable market price for power for delivery in the current year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining
natural gas prices and the impact of the stay of the CSAPR. For example, from December 31, 2011, through February 29, 2012, the market price for power at the Indiana Hub for delivery in the current year decreased by 14%. As a result of
this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. The sharp decline in the market price of power in the first
quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco’s Newton energy center scrubber project, caused Merchant Generation and Genco to evaluate, during the first quarter of 2012,
whether the carrying values of their coal-fired energy centers were recoverable. The carrying values of Merchant Generation’s and Genco’s energy centers exceeded their estimated fair values.
61
However, under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment
loss is recognized, even if the carrying values of the assets exceed estimated fair values. Only AERG’s Duck Creek energy center’s carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash
pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value during the first quarter of 2012. This impairment charge was included in Ameren’s results and in the
Merchant Generation segment’s results for the first quarter of 2012 and the nine months ended September 30, 2012.
Key assumptions used in the determination of estimated undiscounted cash flows of the Merchant Generation and Genco long-lived assets
tested for impairment included the forward price projections for energy and fuel costs, the expected life of the energy center, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a
discount rate, were used to estimate the fair value of the long-lived assets of the Duck Creek energy center. The fair value estimate of the long-lived assets of the Duck Creek energy center was based on the income approach, which considers
discounted future cash flows. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.
After the impairment of the Duck Creek energy center, Merchant Generation and Genco believed the carrying value of their energy centers
exceeded their estimated fair values by an amount significantly in excess of $1 billion. Merchant Generation and Genco will continue to monitor the market price for power and the related impact on electric margin and other events or changes in
circumstances that indicate that the carrying value of their energy centers may not be recoverable as compared to their undiscounted cash flows. Merchant Generation and Genco could recognize additional, material long-lived asset impairment charges
in the future as a result of factors outside their control, such as changes in power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of
Merchant Generation’s and Genco’s energy centers, and also as a result of factors that may be within their control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating
results and cash flows, or decisions to shut down, mothball or sell their energy centers.
The Duck Creek energy center asset
impairment charge did not result in a violation of any Ameren debt covenants or counterparty agreements.
During the third
quarter of 2011, the MoPSC issued an electric rate order that disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of the
amount recovered from property insurance. Consequently, Ameren and Ameren Missouri each reported a pretax charge to earnings of $89 million. Also during 2011, Resources Company announced that a total of four units at Genco’s Meredosia and
Hutsonville energy centers would cease operations at the end of 2011. As a result of these closures, Ameren and Genco each recorded a charge to earnings in the third quarter of 2011 of $35 million. See Note 1 - Summary of Significant Accounting
Policies for information regarding the intangible asset impairment recorded in 2011.
NOTE 12 - RETIREMENT BENEFITS
Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to meet federal
funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31,
2011, its estimated investment performance through September 30, 2012, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $150 million in each of the next five years, with aggregate estimated
contributions of $560 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for
postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
62
The following table presents the components of the net periodic benefit cost for
Ameren’s pension and postretirement benefit plans for the three and nine months ended September 30, 2012, and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
(a)
|
|
|
Postretirement Benefits
(a)
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Service cost
|
|
$
|
21
|
|
|
$
|
19
|
|
|
$
|
62
|
|
|
$
|
57
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
18
|
|
|
$
|
17
|
|
|
Interest cost
|
|
|
43
|
|
|
|
45
|
|
|
|
128
|
|
|
|
135
|
|
|
|
13
|
|
|
|
15
|
|
|
|
39
|
|
|
|
44
|
|
|
Expected return on plan assets
|
|
|
(53
|
)
|
|
|
(54
|
)
|
|
|
(160
|
)
|
|
|
(162
|
)
|
|
|
(15
|
)
|
|
|
(14
|
)
|
|
|
(44
|
)
|
|
|
(41
|
)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
2
|
|
|
Prior service cost (benefit)
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
(5
|
)
|
|
|
(6
|
)
|
|
Actuarial loss
|
|
|
19
|
|
|
|
10
|
|
|
|
58
|
|
|
|
31
|
|
|
|
2
|
|
|
|
1
|
|
|
|
6
|
|
|
|
3
|
|
|
Curtailment loss
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
(b
|
)
|
|
|
-
|
|
|
|
(b
|
)
|
|
|
-
|
|
|
Net periodic benefit cost
|
|
$
|
31
|
|
|
$
|
20
|
|
|
$
|
88
|
|
|
$
|
60
|
|
|
$
|
5
|
|
|
$
|
7
|
|
|
$
|
16
|
|
|
$
|
19
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
|
|
(b)
|
Less than $1 million.
|
As
discussed in Note 1 - Summary of Significant Accounting Policies, EEI substantially completed an employee reduction program during the third quarter of 2012. The employee reduction resulted in a curtailment of EEI’s pension and management
postretirement benefit plans, which are separate from Ameren’s pension and postretirement benefit plans. The EEI curtailment resulted in a curtailment loss of $2 million, which was included in Ameren’s and Genco’s “Other
operations and maintenance” expenses on their consolidated statements of income for the three and nine months ended September 30, 2012.
Separately, in 2012, EEI’s pension plan was amended to adjust the calculation of the future benefit obligation for all of its active employees from a traditional, final pay formula to a cash balance
formula. This plan amendment resulted in a $6 million benefit obligation reduction and a corresponding offset to accumulated other comprehensive income. Additionally, in 2012, EEI’s management and labor union postretirement medical benefit
plans were amended to adjust for moving to a Medicare Advantage plan. This plan amendment triggered a remeasurement of the benefit obligation as of September 30, 2012. This plan amendment and remeasurement resulted in a net $70 million benefit
obligation reduction with a corresponding offset to accumulated other comprehensive income as of September 30, 2012. The impact of these EEI plan amendments were reflected in Ameren’s consolidated statement of comprehensive income and
Genco’s consolidated statement of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2012.
Ameren Missouri, Ameren Illinois and Genco are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs
incurred for the three and nine months ended September 30, 2012, and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Costs
|
|
|
Postretirement Costs
|
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Ameren Missouri
|
|
$
|
16
|
|
|
$
|
13
|
|
|
$
|
48
|
|
|
$
|
39
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
7
|
|
|
$
|
8
|
|
|
Ameren Illinois
|
|
|
9
|
|
|
|
4
|
|
|
|
27
|
|
|
|
12
|
|
|
|
1
|
|
|
|
3
|
|
|
|
3
|
|
|
|
9
|
|
|
Genco
(a)
|
|
|
4
|
|
|
|
1
|
|
|
|
9
|
|
|
|
6
|
|
|
|
2
|
|
|
|
1
|
|
|
|
6
|
|
|
|
2
|
|
|
Other
|
|
|
2
|
|
|
|
2
|
|
|
|
4
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Ameren
(a)(b)
|
|
$
|
31
|
|
|
$
|
20
|
|
|
$
|
88
|
|
|
$
|
60
|
|
|
$
|
5
|
|
|
$
|
7
|
|
|
$
|
16
|
|
|
$
|
19
|
|
|
(a)
|
Includes EEI’s pension and management postretirement benefit plans’ $2 million curtailment loss recognized in the third quarter of 2012 as a result of its
employee reduction program.
|
|
(b)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
|
NOTE 13 - SEGMENT INFORMATION
Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri
segment for Ameren and Ameren Missouri includes all the operations of Ameren Missouri’s business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren Illinois segment for Ameren and Ameren Illinois includes all of the
operations of Ameren Illinois’ business as described in Note 1 - Summary of Significant Accounting Policies. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, including EEI, AERG, Medina
Valley, and Marketing Company. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI.
63
The following table presents information about the revenues and specified items included in
Ameren’s net income for the three and nine months ended September 30, 2012, and 2011, and total assets as of September 30, 2012, and December 31, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Ameren
Missouri
|
|
|
Ameren
Illinois
|
|
|
Merchant
Generation
|
|
|
Other
|
|
|
Intersegment
Eliminations
|
|
|
Consolidated
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
1,059
|
|
|
$
|
642
|
|
|
$
|
299
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
2,001
|
|
|
Intersegment revenues
|
|
|
5
|
|
|
|
6
|
|
|
|
83
|
|
|
|
1
|
|
|
|
(95
|
)
|
|
|
-
|
|
|
Net income (loss) attributable to Ameren Corporation
(a)
|
|
|
236
|
|
|
|
71
|
|
|
|
20
|
|
|
|
47
|
(b)
|
|
|
-
|
|
|
|
374
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
1,109
|
|
|
$
|
742
|
|
|
$
|
415
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
2,268
|
|
|
Intersegment revenues
|
|
|
6
|
|
|
|
3
|
|
|
|
67
|
|
|
|
2
|
|
|
|
(78
|
)
|
|
|
-
|
|
|
Net income (loss) attributable to Ameren Corporation
(a)
|
|
|
190
|
|
|
|
98
|
|
|
|
(9
|
)
|
|
|
6
|
|
|
|
-
|
|
|
|
285
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
2,583
|
|
|
$
|
1,924
|
|
|
$
|
809
|
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
5,319
|
|
|
Intersegment revenues
|
|
|
16
|
|
|
|
12
|
|
|
|
242
|
|
|
|
3
|
|
|
|
(273
|
)
|
|
|
-
|
|
|
Net income (loss) attributable to Ameren Corporation
(a)
|
|
|
400
|
|
|
|
130
|
|
|
|
(348
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
182
|
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
2,690
|
|
|
$
|
2,166
|
|
|
$
|
1,094
|
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
5,953
|
|
|
Intersegment revenues
|
|
|
19
|
|
|
|
10
|
|
|
|
163
|
|
|
|
3
|
|
|
|
(195
|
)
|
|
|
-
|
|
|
Net income (loss) attributable to Ameren Corporation
(a)
|
|
|
301
|
|
|
|
168
|
|
|
|
26
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
494
|
|
|
As of September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
12,967
|
|
|
$
|
7,227
|
|
|
$
|
3,240
|
|
|
$
|
1,125
|
|
|
$
|
(1,061
|
)
|
|
$
|
23,498
|
|
|
As of December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
12,757
|
|
|
$
|
7,213
|
|
|
$
|
3,833
|
|
|
$
|
1,211
|
|
|
$
|
(1,369
|
)
|
|
$
|
23,645
|
|
|
(a)
|
Represents net income (loss) available to common stockholders.
|
|
(b)
|
The increase in net income attributable to Ameren Corporation in Other primarily relates to an increase in income tax benefit as a result of the reversal of the income
tax benefit reduction recognized in conjunction with the first quarter 2012 long-lived asset impairment of Merchant Generation’s Duck Creek energy center. The income tax benefit reduction resulted from the requirement under authoritative
accounting guidance to recognize interim income tax expense (benefit) using the annual estimated effective tax rate and fully reversed over the first nine months of 2012.
|
